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pdfUNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. _______
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
BAL-002-3
Shamai Elstein
Senior Counsel
Candice Castaneda
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
August 17, 2018
TABLE OF CONTENTS
I.
EXECUTIVE SUMMARY................................................................................................................. 2
II. NOTICES AND COMMUNICATIONS ........................................................................................... 4
III. BACKGROUND ................................................................................................................................. 4
A.
REGULATORY FRAMEWORK ................................................................................................. 4
B.
NERC Reliability Standards Development Procedure ................................................................ 5
C.
Procedural History of Proposed Reliability Standard BAL-002-3 ............................................. 6
IV. JUSTIFICATION FOR APPROVAL ............................................................................................... 7
V.
A.
Proposed Reliability Standard BAL-002-3 ................................................................................... 7
B.
Justification for Proposed Reliability Standard BAL-002-3 ....................................................... 9
C.
Enforceability of Proposed Reliability Standard BAL-002-3 ................................................... 10
EFFECTIVE DATE.......................................................................................................................... 11
VI. CONCLUSION ................................................................................................................................. 11
Exhibit A
Exhibit B
Exhibit C
Exhibit D
Exhibit E
Exhibit F
Proposed Reliability Standard BAL-002-3
Implementation Plan
Order No. 672 Criteria
Summary of Development and Complete Record of Development
Rationale for BAL-002-3
Standard Drafting Team Roster
i
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. _______
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD BAL-002-3
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 of the
regulations of the Federal Energy Regulatory Commission (“FERC” or “Commission”), 2 the
North American Electric Reliability Corporation (“NERC”) 3 hereby requests that the
Commission approve: (i) proposed Reliability Standard BAL-002-3 (Disturbance Control
Performance – Contingency Reserve for Recovery from a Balancing Contingency Event)
(Exhibit A) as just, reasonable, not unduly discriminatory or preferential, and in the public
interest; (ii) the associated Implementation Plan (Exhibit B); and (iii) the retirement of currentlyeffective Reliability Standard BAL-002-2. Proposed Reliability Standard BAL-002-3 will apply
the same Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) as applicable
to currently effective Reliability Standard BAL-002-2. Therefore, this petition does not include
a separate justification for the VRFs and VSLs.
As required by section 39.5(a) of the Commission’s regulations, 4 this Petition presents
the technical basis and purpose of the proposed Reliability Standard, a demonstration that the
proposed Reliability Standard meets the criteria identified by the Commission in Order No. 672 5
1
16 U.S.C. § 824o (2012).
18 C.F.R. § 39.5 (2017).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with section 215 of the
FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006). Terms not otherwise defined herein, are
defined in the proposed Reliability Standard BAL-002-3 and the NERC Glossary.
4
18 C.F.R. § 39.5(a).
5
The Commission specified in Order No. 672 certain general factors it would consider when assessing whether a
particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric Reliability Organization;
and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
2
1
(Exhibit C), and a summary of the standard development history (Exhibit D). The proposed
Reliability Standard was adopted by the NERC Board of Trustees on August 16, 2018.
I.
EXECUTIVE SUMMARY
Reliable operation of the Bulk Power System depends on the ability of responsible
entities to balance resources and demand and to recover from a system contingency through
frequency restoration and the deployment of reserves necessary to replace lost capacity and
energy. Reliability Standard BAL-002-3 is designed to ensure that “the Balancing Authority
[(“BA”)] or Reserve Sharing Group [(“RSG”)] balances resources and demand and returns the
[BA]’s or [RSG]’s Area Control Error [(“ACE”)] to defined values (subject to applicable limits)
following a Reportable Balancing Contingency Event.” To support this goal, Requirement R1
mandates certain actions upon a Reportable Balancing Contingency Event to (i) return Reporting
ACE to defined values within the Contingency Event Recovery Period; (ii) document Reportable
Balancing Contingency Events; and (iii) deploy Contingency Reserves. Within this rubric,
Requirement R1 Part 1.3 provides a limited exemption from the BA’s or RSG’s obligation to
restore Reporting ACE within the Contingency Event Recovery Period if the entity is recovering
from an emergency event under NERC Emergency Preparedness and Operations (“EOP’)
Reliability Standards and meets certain other qualifications.
In Order No. 835, the Commission approved Reliability Standard BAL-002-2 while
highlighting the “need to address the underlying concern . . . that a balancing authority that is
operating out-of-balance for an extended period of time is ‘leaning on the system’ . . . .” 6
Accordingly, the Commission directed NERC to revise the standard to require an entity seeking
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at PP 262, 321-37, order on reh’g, Order No. 672-A, FERC Stats. &
Regs. ¶ 31,212 (2006) (“Order No. 672”).
6
Disturbance Control Standard—Contingency Reserve for Recovery from a Balancing Contingency Event Reliability
Standard, Order No. 835, 158 FERC ¶ 61,030, at P 35 (2017) (“Order No. 835”).
2
to avail itself of the exemption in Requirement R1.3 “to obtain an extension of the 15-minute
ACE recovery period by informing the reliability coordinator [(“RC”)]of the circumstances and
providing it with an ACE recovery plan and target time period.” 7
In response to Order No. 835, NERC established Project 2017-06 to develop revisions to
Reliability Standard BAL-002-2 to implement the Commission’s directive. The standard
drafting team’s (“SDT’s”) proposed modifications also intend to clarify that communication with
the RC should proceed in accordance with Energy Emergency Alert procedures within the EOP
Reliability Standards. The proposed modifications would ensure that Reliability Standard BAL002-3 addresses the Commission’s concern in a manner that coordinates with emergency
procedures in other Reliability Standards. NERC respectfully requests that the Commission
approve proposed Reliability Standard BAL-002-3 and the associated Implementation Plan as
just, reasonable, not unduly discriminatory or preferential, and in the public interest.
7
Id.
3
II.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the
following:
Shamai Elstein*
Senior Counsel
Candice Castaneda*
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
III.
Howard Gugel*
Director of Standards
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
[email protected]
BACKGROUND
A. REGULATORY FRAMEWORK
By enacting the Energy Policy Act of 2005, 8 Congress entrusted the Commission with
the duties of approving and enforcing rules to ensure the reliability of the Nation’s Bulk-Power
System, and certifying an Electric Reliability Organization (“ERO”) that would be charged with
developing and enforcing mandatory Reliability Standards, subject to Commission approval.
Section 215(b)(1) of the FPA states that all users, owners, and operators of the Bulk-Power
System in the United States will be subject to Commission-approved Reliability Standards. 9
Section 215(d)(5) of the FPA authorizes the Commission to order the ERO to submit a new or
modified Reliability Standard. 10 Section 39.5(a) of the Commission’s regulation requires the
ERO to file for Commission approval of each Reliability Standard that the ERO proposes should
8
9
10
16 U.S.C. § 824o.
Id. § 824o(b)(1).
Id. § 824o(d)(5).
4
become mandatory and enforceable in the United States, and each modification to a Reliability
Standard that the ERO proposes should be made effective. 11
The Commission is vested with the regulatory responsibility to approve Reliability
Standards that protect the Reliability of the Bulk-Power System and to ensure that such
Reliability Standards are just, reasonable, not unduly discriminatory or preferential, and in the
public interest. Pursuant to Section 215(d)(2) of the FPA 12 and Section 39.5(c) of the
Commission’s regulations, “the Commission will give due weight to the technical expertise of
the Electric Reliability Organization” with respect to the content of a Reliability Standard. 13
B. NERC Reliability Standards Development Procedure
The proposed Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process. 14 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of the NERC Rules of Procedures (“ROP”) and the NERC Standard Processes
Manual (“SPM”). 15
In its order certifying NERC as the Commission’s ERO, the Commission found that
NERC’s proposed rules provide for reasonable notice and opportunity for public comment, due
process, openness, and a balance of interests in developing Reliability Standards, 16 and thus
11
18 C.F.R. § 39.5(a).
16 U.S.C. § 824o(d)(2).
13
18 C.F.R. § 39.5(c)(1).
14
Order No. 672 at P 334 (“Further, in considering whether a proposed Reliability Standard meets the legal standard of
review, we will entertain comments about whether the ERO implemented its Commission-approved Reliability Standard
development process for the development of the particular proposed Reliability Standard in a proper manner, especially whether
the process was open and fair. However, we caution that we will not be sympathetic to arguments by interested parties that
choose, for whatever reason, not to participate in the ERO’s Reliability Standard development process if it is conducted in good
faith in accordance with the procedures approved by the Commission.”).
15
The NERC Rules of Procedure are available at https://www.nerc.com/AboutNERC/Pages/Rules-of-Procedure.aspx.
The NERC Standard Processes Manual is available at
https://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
16
Order No. 672 at P 268.
12
5
satisfy the criteria for approving Reliability Standards. 17 The ANSI-accredited development
process is open to any person or entity with a legitimate interest in the reliability of the BulkPower System. Before a Reliability Standard is submitted to the Commission for approval,
NERC must consider the comments of all stakeholders, the stakeholders must approve of the
Standard, and the Standard must be adopted by the NERC Board of Trustees.
C. Procedural History of Proposed Reliability Standard BAL-002-3
In Order No. 835, the Commission approved Reliability Standard BAL-002-2, noting that
it “improve[d] upon currently-effective Reliability Standard BAL-002-1 by consolidating the
number of requirements to streamline and clarify the obligations for responsible entities to
deploy contingency reserves to stabilize system frequency in response to system
contingencies.” 18 In addition, the Commission directed NERC to: (i) change proposed VRFs for
Requirements R1 and R2 from “medium” to “high”; 19 (ii) collect and report on certain data
pertaining to implementation of the standard within two years from Reliability Standard BAL002-2 implementation; 20 and (iii) develop modifications to the standard to “require an entity to
provide certain information to the reliability coordinator when the entity does not timely recover
ACE due to an intervening disturbance.” 21
With regard to modifications to the standard, the Commission:
[D]irect[ed] NERC to develop modifications to Reliability Standard BAL-002-2,
Requirement R1 to require balancing authorities or reserve sharing groups: (1) to notify
the reliability coordinator of the conditions set forth in Requirement R1, Part 1.3.1
preventing it from complying with the 15-minute ACE recovery period; and (2) to
provide the reliability coordinator with its ACE recovery plan, including a target recovery
time. NERC may also propose an equally efficient and effective alternative. 22
17
Id. at PP 268, 270.
Order No. 835 at P 21.
19
Id. at P 68. NERC has revised the standard in accordance with this directive. See NERC, Docket No. RD17-6-000
(Oct. 2, 2017) (Letter Order) (“Order No. 835 Letter Order”).
20
Order No. 835 at P 46. NERC is collecting data pursuant to this directive and plans to submit an informational filing
by the Commission’s deadline January 2, 2020.
21
Id. at P 2; see also id. at P 35.
22
Order No. 835 at P 37.
18
6
In response to this directive, NERC established Project 2017-06 and the SDT developed
modifications to Reliability Standard BAL-002-2 that would require notification to the RC in
accordance with the Commission’s directive, while leveraging Energy Emergency Alert
procedures in the EOP Reliability Standards. Following two comment and ballot periods,
proposed Reliability Standard BAL-002-3 was approved by the ballot pool by July 16, 2018.
The NERC Board of Trustees adopted the Standard and Implementation Plan on August 16,
2018.
IV.
JUSTIFICATION FOR APPROVAL
As discussed below and in Exhibit C, proposed Reliability Standard BAL-002-3
addresses the Commission’s directive in Order No. 835, satisfies the Commission’s criteria in
Order No. 672, and is just, reasonable, not unduly discriminatory or preferential, and in the
public interest. The following subsections provide: (A) a description of the proposed standard;
(B) justification for the modifications in the proposed standard; and (C) discussion of the
enforceability of the proposed standard.
A. Proposed Reliability Standard BAL-002-3
Proposed Reliability Standard BAL-002-3 is designed to ensure that a BA or RSG
balances resources and demand and returns the ACE to defined values following a Reportable
Balancing Contingency Event. 23 It applies to BAs and RSGs (noting that a BA that is a member
of an RSG is the responsible entity only in periods during which the BA is not in active status
under the RSG). The primary objective of the proposed standard is to ensure that the responsible
entity is prepared to balance resources and demand by requiring the maintenance of adequate
23
See Exhibit E, Rationales for BAL-002-3 (Feb. 2018).
7
reserves and the deployment of those reserves to return its ACE to defined values following a
Reportable Balancing Contingency Event.
In support of this objective, Requirement R1 obligates responsible entities to: (i) return
Reporting ACE to certain values within the Contingency Event Recovery Period (Requirement
R1 Part 1.1); (ii) document Reportable Balancing Contingency Events (Requirement R1 Part
1.3); and (iii) deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events (Requirement R1 Part 1.3). Within this framework,
Requirement R1 Part 1.3.1 also permits an exemption from a responsible entity’s obligation to
demonstrate recovery of Reporting ACE within the Contingency Event Recovery Period under
certain limited circumstances associated with an emergency on the system. In accordance with
the Commission’s directive in Order No. 835, the SDT has proposed the following modifications
to further limit Requirement R1 Part 1.3.1:
8
….
B. Justification for Proposed Reliability Standard BAL-002-3
As discussed above, in Order No. 835, the Commission expressed concern that “a
balancing authority that is operating out-of-balance for an extended period of time is ‘leaning on
the system’” 24 and directed NERC to:
[R]equire balancing authorities or reserve sharing groups: (1) to notify the reliability
coordinator of the conditions set forth in Requirement R1, Part 1.3.1 preventing it from
complying with the 15-minute ACE recovery period; and (2) to provide the reliability
coordinator with its ACE recovery plan, including a target recovery time . . . . 25
24
25
Order No. 835 at P 35.
Id. at P 37.
9
In response, the drafting team modified Requirement R1 Part 11.3.1 of Reliability
Standard BAL-002-2 to clarify and narrow conditions when a BA or RSG may qualify for an
exemption from the time period for recovery of Reporting ACE otherwise applicable under
Requirement R1 Part 1.1 due to emergency conditions. Consistent with the Commission’s
directive, with the modifications in the proposed Reliability Standard, a BA or RSG may only be
exempt from Requirement R1 Part 1.1 if it provides the RC (1) notice of the conditions
warranting an exemption, and (2) an ACE recovery plan. Proposed Reliability Standard BAL002-3 thereby improves upon BAL-002-2 by ensuring coordination with the Reliability
Coordinator before a responsible entity may avail itself of the exemption in Requirement R1.3.1
and addressing concerns that a responsible entity taking advantage of the exemption is “leaning
on the system.”
C. Enforceability of Proposed Reliability Standard BAL-002-3
The proposed Reliability Standard BAL-002-3 includes measures that support each
Requirement to provide guidance to the industry about compliance expectations and to ensure
that the Requirements are enforced in a clear, consistent, non-preferential manner, and without
prejudice to any part. The proposed Reliability Standard VRFs and VSLs associated with each
Requirement are amongst several elements used to determine an appropriate sanction when the
associated Requirement is violated. The VRFs assess the impact to reliability caused by
violations of a specific Requirement. The VSLs guide the method by which NERC will enforce
the Requirements of the proposed Reliability Standards. In this Petition, NERC proposes to
utilize the same VRFs and VSLs in effect for BAL-002-2. These VRFs and VSLs were approved
10
in 2017. 26 Therefore, the VRFs and VSLs in proposed Reliability Standard BAL-002-3 comport
with NERC and Commission Guidelines.
V.
EFFECTIVE DATE
NERC Respectfully requests that the Commission approve proposed Reliability Standard
BAL-002-3, effective on the first day of the first calendar quarter that is six calendar months
after the effective date of the Commission’s order approving the standard and terms, or as
otherwise provided for by the applicable governmental authority. This will provide for
deliberative implementation of the revised Requirement. In addition, NERC requests retirement
of Reliability Standard BAL-002-2. Proposed Reliability Standard BAL-002-3 will replace and
supersede currently-effective Reliability Standard BAL-002-2.
VI.
CONCLUSION
NERC has developed these modifications to Reliability Standard BAL-002-3 to address
the Commission’s directive in Order No. 835 and provide RCs with important information
necessary for coordinated operations of the grid, while maintaining an appropriate level of
flexibility for responsible entities faced with an emergency on the system. For the reasons set
forth above, NERC respectfully requests that the Commission approve (i) proposed Reliability
Standard BAL-002-3 (Exhibit A); (ii) the Implementation Plan (Exhibit B); and (iii) the
retirement of currently-effective Reliability Standard BAL-002-2.
26
Violation Risk Factors were updated after the adoption of BAL-002-2 as per Commission directives in Order No. 835.
See Order No. 835 Letter Order.
11
Respectfully submitted,
/s/ Candice Castaneda
Shamai Elstein
Senior Counsel
Candice Castaneda
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
Date: August 17, 2018
12
Exhibit A
Proposed Reliability Standard
Exhibit A
Proposed Reliability Standard
BAL-002-3 (Disturbance Control Performance –
Contingency Reserve for Recovery from a Balancing Contingency Event)
Clean
BAL-002-3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
A. Introduction
1.
Title: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
2.
Number:
3.
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.
4.
Applicability:
4.1.
BAL-002-3
Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during which the
Balancing Authority is not in active status under the applicable
agreement or governing rules for the Reserve Sharing Group.
4.1.2. Reserve Sharing Group
5.
Effective Date: See the Implementation Plan for BAL-002-3.
B. Requirements and Measures
R1.
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
1.1.
within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
•
zero (if its Pre-Reporting Contingency Event ACE Value was positive or
equal to zero); however, any Balancing Contingency Event that occurs
during the Contingency Event Recovery Period shall reduce the required
recovery: (i) beginning at the time of, and (ii) by the magnitude of, such
individual Balancing Contingency Event,
or,
•
1.2.
its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery
Period shall reduce the required recovery: (i) beginning at the time of, and
(ii) by the magnitude of, such individual Balancing Contingency Event.
document all Reportable Balancing Contingency Events using CR Form 1.
Page 1 of 7
BAL-002-3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
1.3.
deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if the Responsible Entity:
1.3.1 is (i) a Balancing Authority or (ii) a Reserve Sharing Group with at least
one member that:
•
is experiencing a Reliability Coordinator declared Energy Emergency
Alert Level, and
•
is utilizing its Contingency Reserve to mitigate an operating
emergency in accordance with its emergency Operating Plan, and
•
has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency, and
•
has, during communications with its Reliability Coordinator in
accordance with the Energy Emergency Alert procedures, (i) notified
the Reliability Coordinator of the conditions described in the
preceding two bullet points preventing the Responsible Entity from
complying with Requirement R1 part 1.1, and (ii) provided the
Reliability Coordinator with an ACE recovery plan, including target
recovery time
or,
1.3.2 the Responsible Entity experiences:
•
multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or
•
multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.
M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.
R2. Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe Single
Contingency and make preparations to have Contingency Reserve equal to, or greater
than the Responsible Entity’s Most Severe Single Contingency available for
maintaining system reliability. [Violation Risk Factor: High] [Time Horizon: Operations
Planning]
Page 2 of 7
BAL-002-3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
M2. Each Responsible Entity will have the following documentation to show compliance
with Requirement R2:
•
a dated Operating Process;
•
evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,
•
evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency and
that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.
R3. Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency, before
the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
Period resets the beginning of the Contingency Event Recovery Period. [Violation Risk
Factor: Medium] [Time Horizon: Real-time Operations]
M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
C. Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity, or any
entity as otherwise designated by an Applicable Governmental Authority, in
their respective roles of monitoring and/or enforcing compliance with
mandatory and enforceable Reliability Standards in their respective
jurisdictions.
1.2.
Evidence Retention
The following evidence retention period(s) identify the period of time an entity
is required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full-time period
since the last audit.
The Responsible Entity shall retain data or evidence to show compliance for the
current year, plus three previous calendar years, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
Page 3 of 7
BAL-002-3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.3.
Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated Reliability Standard.
1.4.
Additional Compliance Information
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.
Page 4 of 7
BAL-002-3 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
Table of Compliance Elements
R#
R1.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Responsible Entity
achieved less than 100% but
at least 90% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period
The Responsible Entity
achieved less than 90% but
at least 80% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 80% but
at least 70% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 70% of
required recovery from a
Reportable Balancing
Contingency Event during
the Contingency Event
Recovery Period.
N/A
The Responsible Entity
developed an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to implement the
Operating Process.
The Responsible Entity failed
to develop an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency.
OR
The Responsible Entity failed
to use CR Form 1 to
document a Reportable
Balancing Contingency
Event.
R2.
The Responsible Entity
developed and implemented
an Operating Process to
determine its Most Severe
Single Contingency and to
have Contingency Reserve
equal to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to maintain
Page 5 of 7
BAL-002-3 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
annually the Operating
Process.
R3.
The Responsible Entity
restored less than 100% but
at least 90% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 90% but
at least 80% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 80% but
at least 70% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event during
the Contingency Event
Restoration Period.
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
CR Form 1
BAL-002-3 Rationales
Page 6 of 7
Supplemental Material
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from
Effective Date
Errata
0
February 14,
2006
Revised graph on page 3, “10
min.” to “Recovery time.”
Removed fourth bullet.
Errata
1
September 9,
2010
Filed petition for revisions to BAL002 Version 1 with the
Commission
Revision
1
January 10, 2011
FERC letter ordered in Docket No.
RD10-15-00 approving BAL-002-1
1
April 1, 2012
Effective Date of BAL-002-1
1a
November 7,
2012
Interpretation adopted by the
NERC Board of Trustees
1a
February 12,
2013
Interpretation submitted to FERC
2
November 5,
2015
Adopted by NERC Board of
Trustees
2
January 19, 2017
FERC Order approved BAL-002-2.
Docket No. RM16-7-000
2
October 2, 2017
FERC letter Order issued
approving raising the VRF for
Requirement R1 and R2 from
Medium to High. Docket No.
RD17-6-000.
3
August 16, 2018
Adopted by NERC Board of
Trustees
3
TBD
FERC Order approving BAL-002-3
Complete revision
Revisions to address
two FERC directives
from Order No. 835
Page 7 of 7
Exhibit A
Proposed Reliability Standard
BAL-002-3 (Disturbance Control Performance –
Contingency Reserve for Recovery from a Balancing Contingency Event)
Redline
BAL-002-32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
A. Introduction
1.
Title: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
2.
Number:
3.
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.
4.
Applicability:
4.1.
BAL-002-32
Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during which the
Balancing Authority is not in active status under the applicable
agreement or governing rules for the Reserve Sharing Group.
4.1.2. Reserve Sharing Group
5.
Effective Date: See the Implementation Plan for BAL-002-32.
B. Requirements and Measures
R1.
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
1.1.
within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
•
zero (if its Pre-Reporting Contingency Event ACE Value was positive or
equal to zero); however, any Balancing Contingency Event that occurs
during the Contingency Event Recovery Period shall reduce the required
recovery: (i) beginning at the time of, and (ii) by the magnitude of, such
individual Balancing Contingency Event,
or,
•
1.2.
its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery
Period shall reduce the required recovery: (i) beginning at the time of, and
(ii) by the magnitude of, such individual Balancing Contingency Event.
document all Reportable Balancing Contingency Events using CR Form 1.
Page 1 of 7
BAL-002-32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
1.3.
deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if the Responsible Entity:
1.3.1 is (i) a Balancing Authority or (ii) a Reserve Sharing Group with at least
one member thatthe Responsible Entity:
•
is a Balancing Authority experiencing a Reliability Coordinator
declared Energy Emergency Alert Level or is a Reserve Sharing Group
whose member, or members, are experiencing a Reliability
Coordinator declared Energy Emergency Alert level, and
•
is utilizing its Contingency Reserve to mitigate an operating
emergency in accordance with its emergency Operating Plan, and
•
has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency, and
•
has, during communications with its Reliability Coordinator in
accordance with the Energy Emergency Alert procedures, (i) notified
the Reliability Coordinator of the conditions described in the
preceding two bullet points preventing the Responsible Entity from
complying with Requirement R1 part 1.1, and (ii) provided the
Reliability Coordinator with an ACE recovery plan, including target
recovery time
or,
1.3.2 the Responsible Entity experiences:
•
multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or
•
multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.
M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.
R2. Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe Single
Contingency and make preparations to have Contingency Reserve equal to, or greater
than the Responsible Entity’s Most Severe Single Contingency available for
maintaining system reliability. [Violation Risk Factor: High] [Time Horizon: Operations
Planning]
Page 2 of 7
BAL-002-32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
M2. Each Responsible Entity will have the following documentation to show compliance
with Requirement R2:
•
a dated Operating Process;
•
evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,
•
evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency and
that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.
R3. Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency, before
the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
Period resets the beginning of the Contingency Event Recovery Period. [Violation Risk
Factor: Medium] [Time Horizon: Real-time Operations]
M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
C. Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity, or any
entity as otherwise designated by an Applicable Governmental Authority, in
their respective roles of monitoring and/or enforcing compliance with
mandatory and enforceable Reliability Standards in their respective
jurisdictions.
1.2.
Evidence Retention
The following evidence retention period(s) identify the period of time an entity
is required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full-time period
since the last audit.
The Responsible Entity shall retain data or evidence to show compliance for the
current year, plus three previous calendar years, unless directed by its
Page 3 of 7
BAL-002-32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.3.
Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated Reliability Standard.
1.4.
Additional Compliance Information
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.
Page 4 of 7
BAL-002-32 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
Table of Compliance Elements
R#
R1.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Responsible Entity
achieved less than 100% but
at least 90% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period
The Responsible Entity
achieved less than 90% but
at least 80% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 80% but
at least 70% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 70% of
required recovery from a
Reportable Balancing
Contingency Event during
the Contingency Event
Recovery Period.
N/A
The Responsible Entity
developed an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to implement the
Operating Process.
The Responsible Entity failed
to develop an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency.
OR
The Responsible Entity failed
to use CR Form 1 to
document a Reportable
Balancing Contingency
Event.
R2.
The Responsible Entity
developed and implemented
an Operating Process to
determine its Most Severe
Single Contingency and to
have Contingency Reserve
equal to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to maintain
Page 5 of 7
BAL-002-32 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
annually the Operating
Process.
R3.
The Responsible Entity
restored less than 100% but
at least 90% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 90% but
at least 80% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 80% but
at least 70% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event during
the Contingency Event
Restoration Period.
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event Background Document
CR Form 1
BAL-002-3 Rationales
Page 6 of 7
Supplemental Material
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from
Effective Date
Errata
0
February 14,
2006
Revised graph on page 3, “10
min.” to “Recovery time.”
Removed fourth bullet.
Errata
1
September 9,
2010
Filed petition for revisions to BAL002 Version 1 with the
Commission
Revision
1
January 10, 2011
FERC letter ordered in Docket No.
RD10-15-00 approving BAL-002-1
1
April 1, 2012
Effective Date of BAL-002-1
1a
November 7,
2012
Interpretation adopted by the
NERC Board of Trustees
1a
February 12,
2013
Interpretation submitted to FERC
2
November 5,
2015
Adopted by NERC Board of
Trustees
2
January 19, 2017
FERC Order approved BAL-002-2.
Docket No. RM16-7-000
2
October 2, 2017
FERC letter Order issued
approving raising the VRF for
Requirement R1 and R2 from
Medium to High. Docket No.
RD17-6-000.
3
August 16, 2018
Adopted by NERC Board of
Trustees
3
TBD
FERC Order approving BAL-002-3
Complete revision
Revisions to address
two FERC directives
from Order No. 835
Page 7 of 7
Exhibit B
Implementation Plan
Implementation Plan
Project 2017-06 Modifications to BAL-002-2
Requested Approvals
BAL‐002‐3 Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event
Requested Retirements
BAL‐002‐2 Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event
Applicable Entities
Balancing Authority
Reserve Sharing Group
Effective Date
The effective date for proposed Reliability Standard BAL‐002‐3 is provided below:
Where approval by an applicable governmental authority is required, Reliability Standard BAL‐002‐3
shall become effective the first day of the first calendar quarter that is six (6) calendar months after
the effective date of the applicable governmental authority’s order approving the standards and
terms, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, Reliability Standard BAL‐
002‐3 shall become effective on the first day of the first calendar quarter that is six (6) calendar
months after the date the standards and terms are adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.
Retirement Date
Current NERC Reliability Standards
The existing standard BAL‐002‐2 shall be retired immediately prior to the effective date of the
proposed BAL‐002‐3 standard.
Exhibit C
Order No. 672 Criteria
Exhibit C
Order No. 672 Criteria
In Order No. 672, the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. 1 The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria:
1. Proposed Reliability Standards must be designed to achieve a specific reliability
goal and must contain a technically sound means to achieve that goal. 2
Proposed Reliability Standard BAL-002-3 achieves the specific reliability goal of
ensuring that the Balancing Authority or Reserve Sharing Group balances resources and demand
and returns the Balancing Authority’s or Reserve Sharing Group’s Area Control Error to defined
values (subject to applicable limits) following a reportable Balancing Contingency Event.
Proposed Reliability Standard BAL-002-3 tightens an exception to BAL-002 Requirement R1
(as expressed in Requirement R1 Part 1.3.1) in which a Responsible Entity (Balancing Authority
or Reserve Sharing Group) receives relief from compliance to Requirement R1 during a
Reportable Balance Contingency Event in which that Responsible Entity is (1) experiencing a
Reliability Coordinator declared Energy Emergency Alert Level, (2) is utilizing its contingency
Reserve to mitigate an operating emergency in accordance with its emergency Operating Plan, or
(3) has depleted its Contingency Reserve to a level below its Most Severe Single Contingency,
by requiring that the Responsible Entity notify the Reliability Coordinator that the Responsible
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment,
Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, order on reh’g,
Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 at PP 321, 324.
Entity is experiencing the aforementioned conditions, and to provide the Reliability Coordinator
with an ACE recovery plan, including a target recovery time.
2. Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply. 3
The proposed Reliability Standard applies to Reserve Sharing Groups and a Balancing
Authorities, but a Balancing Authority that is a member of a Reserve Sharing Group is the
Responsible Entity only in periods during which the Balancing Authority is not in active status
under the applicable agreement or governing rules for the Reserve Sharing Group. The proposed
Reliability Standard clearly articulates the actions that such entities must take to comply with the
standard, each of which are triggered by articulable actions.
3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 4
The Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for the
proposed Reliability Standard comport with NERC and Commission guidelines related to their
assignment. The assignment of the severity level for each VSL is consistent with the
corresponding Requirement and will ensure uniformity and consistency in the determination of
penalties. The VSLs do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations. For these reasons, the
proposed Reliability Standard includes clear and understandable consequences in accordance
with Order No. 672.
3
Order No. 672 at PP 322, 325.
Order No. 672 at P 326. The possible consequences, including range of possible penalties, for violating a proposed
Reliability Standard should be clear and understandable by those who must comply.
4
4. A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and nonpreferential manner. 5
The proposed Reliability Standard contains Measures that support each Requirement by
clearly identifying what is required to demonstrate compliance and how the Requirement will be
enforced. The Measures are as follows:
M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR
Form 1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates compliance
with Requirement R1 part 1.3 must also be provided.
M2. Each Responsible Entity will have the following documentation to show compliance
with Requirement R2:
• a dated Operating Process;
• evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,
• evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency and
that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.
M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
The Above Measures work in coordination with the respective Requirements to ensure
that the Requirements will each be enforced in a clear, consistent, and non-preferential manner
without prejudice to any party.
5. Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently – but do not necessarily have to reflect “best practices” without regard to
implementation cost or historical regional infrastructure design. 6
The proposed Reliability Standard achieves the reliability goal effectively and efficiently
in accordance with Order No. 672. The proposed Reliability Standard clearly enumerates the
5
6
Order No. 672 at P 327.
Order No. 672 at P 328.
responsibilities of applicable entities with respect to balancing resources and demands, including
deployment and subsequent recovery of adequate levels of Contingency Reserves, to return the
Area Control Error to defined values. The proposed Reliability Standard provides entities with
the flexibility to tailor their processes and plans to take into account system dynamics and
characteristics while still maintaining reliability of the Bulk Power System.
6. Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power system
reliability. Proposed Reliability Standards can consider costs to implement for
smaller entities but not at consequences of less than excellence in operating system
reliability. 7
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. To the contrary, the proposed standard represents significant benefits for the reliability
of the Bulk Power System because it requires entities to protect system stability by recovering an
entity’s Reporting Area Control Error and requisite levels of Contingency Reserves. The
proposed Reliability Standard does not sacrifice excellence in operating system reliability for
costs associated with implementation of the Reliability Standard.
7. Reliability Standards must be designed to apply throughout North America to the
maximum extent achievable with a single Reliability Standard while not favoring
one geographic area or regional model. It should take into account regional
variations in the organization and corporate structures of transmission owners and
operators, variations in generation fuel type and ownership patterns, and regional
variations in market design if these affect the proposed Reliability Standard. 8
The proposed Reliability Standard applies throughout North America and does not favor
one geographic area or regional model.
7
8
Order No. 672 at P 329-30.
Order No. 672 at P 331.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability. 9
The proposed Reliability Standard has no undue negative impact on competition. The
proposed Reliability Standard requires the same performance by each applicable entity. The
standard does not unreasonably restrict the available transmission capability or limit use of the
Bulk-Power System in a preferential manner.
9. The implementation time for the proposed Reliability Standard is reasonable. 10
The proposed effective date for the standard is just and reasonable and appropriately
balances the urgency in the need to implement the standard against the reasonableness of the
time allowed for those who must comply to develop necessary procedures, software, facilities,
staffing or other relevant capability. The proposed Implementation Plan, attached as Exhibit B,
will allow applicable entities adequate time to ensure compliance with the requirements. The
proposed effective date is explained in the attached Implementation Plan for BAL-002-3
10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 11
The proposed Reliability Standard was developed in accordance with NERC’s
Commission approved, ANSI-accredited processes for developing and approving Reliability
Standards. 12 Exhibit D includes a summary of the Reliability Standard development proceedings
and details the processes followed to develop the Reliability Standard. These processes included,
among other things, multiple comment periods, pre-ballot review periods, and balloting periods.
9
Order No. 672 at P 332.
Order No. 672 at P 333.
11
Order No. 672 at P 334.
12
See NERC Rules of Procedure, Section 300 (Reliability Standards Development) and Appendix 3A (Standard
Processes Manual).
10
Additionally, all meetings of the standard drafting team were properly noticed and open to the
public.
11. NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.13
NERC has identified no competing public interests regarding the request for approval of
proposed Reliability Standard BAL-002-3. No comments were received that indicated the
proposed Reliability Standard BAL-002-3. No comments were received that indicated the
proposed Reliability Standard conflict with other vital public interests.
12. Proposed Reliability Standards must consider any other appropriate factors. 14
NERC has identified no other factors relevant to whether the proposed Reliability
Standard BAL-002-3 is just and reasonable.
13
14
Order No. 672 at P 335.
Order No. 672 at P 323.
Exhibit D
Summary of Development History and Complete Record of Development
Summary of Development History
Summary of Development History
The development record for proposed Reliability Standard BAL-002-3 is summarized
below.
I. Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to give “due
weight” to the technical expertise of the ERO. 1 The technical expertise of the ERO is derived from
the standard drafting team selected to lead each project in accordance with Section 4.3 of the
NERC Standards Process manual. 2 For this project, the standard drafting team consisted of
industry experts, all with a diverse set of experiences. A roster of the Standard Drafting Team is
included in Exhibit F.
II. Standard Development History
A. Standard Authorization Request Development
The Standard Authorization Request (“SAR”) for Project 2017-06 – Modifications to BAL002-2 - Disturbance Control Standard—Contingency Reserve for Recovery from a Balancing
Contingency Event was posted for a 30-day comment period from June 20, 2017 through July 20,
2017. The final SAR was posted on March 13, 2018. Following two solicitations for nominations,
the Standards Committee (“SC”) appointed a SAR drafting team at its October 18, 2017 meeting.
The SAR was approved by the SC on February 14, 2018.
B. First Posting – Comment Period, Initial Ballot and Non-binding Poll
Proposed Reliability Standard BAL-002-3, the associated Implementation Plan, and the
Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) were posted for a 45-
1
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. § 824(d) (2) (2012).
The NERC Standard Processes Manual is available at
https://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
2
1
day formal public comment period from March 22, 2018 through May 8, 2018, with a parallel
Initial Ballot and Non-binding Poll held during the last 10 days of the comment period from April
27, 2018 through May 7, 2018. The initial ballot received 81.82% quorum, and 69.46% approval.
The non-binding pill received 80% quorum and 77.19% of supportive opinions. There were 30
responses, including comments from approximately 115 different individuals and approximately
87 companies representing all 10 industry segments. 3
C. Final Draft
Proposed Reliability Standard BAL-002-3 was posted for a 10-day final ballot period from
July 5, 2018 through July 16, 2018. The Proposed Reliability Standard received a quorum of
84.42% and an approval rating of 71.85%.
D. Board of Trustees Approval
Proposed Reliability Standard BAL-002-3 was adopted by the NERC Board of Trustees on
August 16, 2018. 4
3
NERC, Consideration of Comments, Project 2017-06 - – Modifications to BAL-002-2,
https://www.nerc.com/pa/Stand/Project_201706_Modifications_to_BAL0022_DL/2017-06_Mod_to_BAL002_Consideration_of_Comments_07052018.pdf.
4
NERC, Board of Trustees Agenda Package, Agenda Item 7c (BAL-002-3 Disturbance Control Standard –
Contingency Reserve for Recovery from a Balancing Contingency Event),
https://www.nerc.com/gov/bot/Agenda%20highlights%20and%20Mintues%202013/Board_Open_Meeting_Agenda
_Package_August_16_2018.pdf.
2
Complete Record of Development
Home > Program Areas & Departments > Standards > Project 2017-06 Modifications to BAL-0022
Project 2017-06 Modifications to BAL-002-2
Related Files
Status
The final ballot for BAL-002-3 Disturbance Control Standard—Contingency Reserve for Recovery
from a Balancing Contingency Event concluded 8 p.m. Eastern, Monday, July 16, 2018. The voting
results are available via the link below. The standard will be submitted to the Board of Trustees for adoption
then filed with the appropriate regulatory authorites.
Background
On January 19, 2017, FERC issued an order approving Reliability Standard BAL-002-2. FERC Order also
directed NERC to make two modifications to the BAL-002-2 standard and revise two VRFs. The revision for the
VRFs will be handled outside of this SAR.
With regard to FERC’s directed modifications to BAL-002-2, the order stated:
“Accordingly, we direct NERC to develop modifications to Reliability Standard BAL-002-2, Requirement R1 to
require Balancing Authorities (BA) or Reserve Sharing Groups (RSG): (1) to notify the reliability coordinator of
the conditions set forth in Requirement R1, Part 1.3.1 preventing it from complying with the 15-minute ACE
recovery period; and (2) to provide the reliability coordinator with its ACE recovery plan, including a target
recovery time. NERC may also propose an equally efficient and effective alternative.”
Standard(s) Affected – BAL-002-2
Purpose/Industry Need
The primary goal of this SAR is to allow the standard drafting team (SDT) for Project 2017-06, Disturbance
Control to modify standard BAL-002-2 to address the directives of the January 19, 2017 FERC Order, and to
ensure consistency within the NERC body of Reliability Standards.
Draft
Actions
Dates
Results
07/05/18 07/16/18
Ballot Results
(27)
Final Draft
Final Ballot
BAL-002-3
Clean (23) | Redline
(24) to Last Approved
Info (26)
Vote
Implementation Plan
(25)
Draft 1
BAL-002-3
Clean (11) | Redline
(12) to Last Approved
Initial Ballot
and Nonbinding Poll
04/27/18 05/08/18
Ballot Results
(18)
Non-binding
Poll Results
(19)
Consideration of
Comments
Implementation Plan
(13)
Supporting
Materials
Updated Info
Extended an
additional day to
(16)
reach quorum
Info (17)
Vote
Unofficial Comment
Form (Word) (14)
Rationales for BAL002-3 (15)
Comment
Period
03/22/18 05/08/18
Info (20)
Submit
Comments
Join Ballot
Pools
03/22/18 04/20/18
For
Informational
Purposes
Only
03/13/18
Supplemental
Supplemental
Standards
Nomination
Authorization Request
Period
Drafting Team
Info (9)
Nominations
Submit
Nominations
Supporting
Materials
Unofficial
Nomination Form
(Word) (8)
07/27/17 08/09/17
Standards Authorization
Request (10)
Comments
Received (21)
Consideration of
Comments(22)
Standards Authorization
Request (3)
Supporting Materials
Unofficial Comment Form
(Word) (4)
Standards Authorization
Request Drafting Team
Nominations
Supporting Materials
Unofficial Nomination Form
(Word) (1)
Comment Period
Info (5)
06/20/17 07/20/17
Submit
Comments
Nomination
Period
Info (2)
Submit
Nominations
06/20/17 07/03/17
Comments
Received (6)
Consideration of
Comments (7)
Unofficial Nomination Form
Project 2017-06 Modifications to BAL-002-2 Standards Authorization
Request Drafting Team
Do not use this form for submitting nominations. Use the electronic form to submit nominations by 8
p.m. Eastern, Monday, July 3, 2017. This unofficial version is provided to assist nominees in compiling the
information necessary to submit the electronic form.
Additional information about this project is available on the Project 2017-06 Modifications to BAL-002-2
page. If you have questions, contact Senior Standards Developer Darrel Richardson, (via email), or at
(609) 613-1848.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
Previous drafting or review team experience is beneficial, but not required. A brief description of the
desired qualifications, expected commitment, and other pertinent information is included below.
Project 2017-06 Modifications to BAL-002-2
The primary goal of this SAR is to allow the standard drafting team (SDT) for Project 2017-06, Disturbance
Control to modify standard BAL-002-2 to address the directives of the January 19, 2017 FERC Order, and
to ensure consistency within the NERC body of Reliability Standards.
On January 19, 2017, FERC issued an order directing the ERO to develop modifications to standard BAL002-2 to address their concerns regarding the 15-minute recovery period set forth in Requirement R1. In
the order, FERC stated:
“Accordingly, we direct NERC to develop modifications to Reliability Standard BAL-002-2,
Requirement R1 to require Balancing Authorities (BA) or Reserve Sharing Groups (RSG): (1) to
notify the reliability coordinator of the conditions set forth in Requirement R1, Part 1.3.1
preventing it from complying with the 15-minute ACE recovery period; and (2) to provide the
reliability coordinator with its ACE recovery plan, including a target recovery time. NERC may also
propose an equally efficient and effective alternative.”
The time commitment for this project is expected to be up to two face-to-face meetings per quarter (on
average two full working days each meeting) with conference calls scheduled as needed to meet the
agreed-upon timeline the review or drafting team sets forth. Team members may also have side projects,
either individually or by subgroup, to present to the larger team for discussion and review. Lastly, an
important component of the review and drafting team effort is outreach. Members of the team will be
expected to conduct industry outreach during the development process to support a successful project
outcome.
We are seeking a cross section of the industry to participate on the team, but in particular are seeking
individuals who have experience and expertise in one or more of the following areas: Reliability
Coordinator operations, transmission operations, Balancing Authority operations and generation
operations. Experience with developing standards inside or outside (e.g., IEEE, NAESB, ANSI, etc.) of the
NERC process is beneficial, but is not required, and should be highlighted in the information submitted, if
applicable.
Individuals who have facilitation skills and experience and/or legal or technical writing backgrounds are
also strongly desired. Please include this in the description of qualifications as applicable.
Standards affected: BAL-002-2
Name:
Organization:
Address:
Telephone:
E-mail:
Please briefly describe your experience and qualifications to serve on the requested Standard
Drafting Team (Bio):
If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Unofficial Nomination Form
Project 2017-06 Modifications to BAL-002-2 | June 2017
2
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
Texas RE
FRCC
MRO
NPCC
RF
SERC
SPP RE
WECC
NA – Not Applicable
Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Select each Function 1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator
1
Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner
These functions are defined in the NERC Functional Model, which is available on the NERC web site.
Unofficial Nomination Form
Project 2017-06 Modifications to BAL-002-2 | June 2017
3
Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:
Name:
Telephone:
Organization:
E-mail:
Name:
Telephone:
Organization:
E-mail:
Provide the name and contact information of your immediate supervisor or a member of your
management who can confirm your organization’s willingness to support your active participation.
Name:
Telephone:
Title:
Email:
Unofficial Nomination Form
Project 2017-06 Modifications to BAL-002-2 | June 2017
4
Standards Announcement
Project 2017-06 Modifications to BAL-002-2
Nomination Period Open through July 3, 2017
Now Available
Nominations are being sought for Standards Authorization Request drafting team members through
8 p.m. Eastern, Monday, July 3, 2017.
Use the electronic form to submit a nomination. If you experience any difficulties in using the
electronic form, contact Wendy Muller. An unofficial Word version of the nomination form is posted
on the Drafting Team Vacancies page and the project page.
Previous drafting or periodic review team experience is beneficial, but not required. See the project
page and unofficial nomination form for additional information.
Next Steps
The Standards Committee is expected to appoint members to the team July 2017. Nominees will be
notified shortly after they have been appointed.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance Senior Standards Developer, Darrel Richardson (via email), or at (609)
613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Authorization Request Form
When completed, please email this form to:
[email protected]
NERC welcomes suggestions to improve the
reliability of the bulk power system through
improved Reliability Standards. Please use this form
to submit your request to propose a new or a
revision to a NERC Reliability Standard.
Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard:
BAL‐002‐2 – Disturbance Control Standard—Contingency Reserve for
Recovery from a Balancing Contingency Event
Date Submitted:
SAR Requester Information
Name:
Darrel Richardson
Organization:
NERC Staff
Telephone:
609.613.1848
Email:
[email protected]
SAR Type (Check as many as applicable)
New Standard
Withdrawal of Existing Standard
Revision to Existing Standard
Urgent Action
SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
On January 19, 2017, FERC issued an order directing the ERO to develop modifications to standard BAL‐
002‐2 to address their concerns regarding the 15‐minute recovery period set forth in Requirement R1.
In the order, FERC stated:
“Accordingly, we direct NERC to develop modifications to Reliability Standard BAL‐002‐2, Requirement
R1 to require Balancing Authorities (BA) or Reserve Sharing Groups (RSG): (1) to notify the reliability
coordinator of the conditions set forth in Requirement R1, Part 1.3.1 preventing it from complying with
SAR Information
the 15‐minute ACE recovery period; and (2) to provide the reliability coordinator with its ACE recovery
plan, including a target recovery time. NERC may also propose an equally efficient and effective
alternative.” Disturbance Control Standard—Contingency Reserve for Recovery from a Balancing
Contingency Event Reliability Standard, 158 FERC ¶ 61,030 at P 37 (2017) (“FERC Order”). See also, id.,
at P 2 and PP 35‐36.
Purpose or Goal (How does this request propose to address the problem described above?):
The primary goal of this SAR is to allow the standard drafting team (SDT) for Project 2017‐06,
Disturbance Control to modify standard BAL‐002‐2 to address the directives of the January 19, 2017
FERC Order, and to ensure consistency within the NERC body of Reliability Standards.
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?):
The objective of this SAR is to provide clear, unambiguous requirements to address the directives in the
January 19, 2017 FERC Order regarding the recovery from a Balancing Contingency Event, or
alternatively propose modifications that address the Commission concerns.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The SDT shall modify the standard, Violation Risk Factors, Violation Severity Levels, and implementation
plan and shall work with compliance on an accompanying RSAW to address the FERC Order directives
described above.
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
The SDTs execution of this SAR requires the SDT to address the FERC Order directives described above
or alternatively propose modifications that address the Commission concerns in the FERC Order. This
SAR will specifically address either (A) revising BAL‐002‐2 to require that BAs and RSGs: (1) notify the
Reliability Coordinator that the BA or RSG cannot comply with the 15‐minute ACE recovery period due
to existence of the conditions as set forth in Requirement R1, Part 1.3.1; and (2) provide the Reliability
Coordinator with an ACE recovery plan that includes a target recovery time; or (B) proposing an equally
efficient and effective alternative.
Standards Authorization Request Form
2
Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Responsible for the real‐time operating reliability of its Reliability
Reliability Coordinator Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Integrates resource plans ahead of time, and maintains load‐
interchange‐resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.
Balancing Authority
Ensures communication of interchange transactions for reliability
Interchange Authority evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.
Planning Coordinator
Assesses the longer‐term reliability of its Planning Coordinator Area.
Resource Planner
Develops a one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission Planner
Develops a one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real‐time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution Provider
Delivers electrical energy to the end‐use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
Purchasing‐Selling
Entity
Purchases or sells energy, capacity, and necessary reliability‐related
services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Standards Authorization Request Form
3
Reliability Functions
Load‐Serving Entity
Secures energy and transmission service (and reliability‐related services)
to serve the end‐use customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall
be trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non‐sensitive information that is required for compliance
with reliability standards.
Enter
(yes/no)
Yes
Yes
Yes
Yes
Standards Authorization Request Form
4
Related Standards
Standard No.
Explanation
None
Related SARs
SAR ID
Explanation
None
Regional Variances
Region Explanation
ERCOT
None.
FRCC
None.
MRO
None.
NPCC
None.
RFC
None.
Standards Authorization Request Form
5
Regional Variances
SERC
None.
SPP
None.
WECC
None.
Version History
Version
Date
Owner
Change Tracking
1
June 3, 2013
Revised
1
August 29, 2014
Standards Information Staff Updated template
Standards Authorization Request Form
6
Unofficial Comment Form
Project 2017-06 Modifications to BAL-002-2
Standards Authorization Request
Do not use this form for submitting comments. Use the electronic form to submit comments on the
Standards Authorization Request (SAR) for BAL-002-2 Disturbance Control Standard—Contingency
Reserve for Recovery from a Balancing Contingency Event. The electronic form must be submitted by 8
p.m. Eastern, Thursday, July 20, 2017.
Documents and information about this project are available on the Project 2017-06 Modifications to BAL002-2 page. If you have questions, contact Senior Standards Developer, Darrel Richardson (via email) or at
(609) 613-1848.
Background
On January 19, 2017, FERC issued an order directing the ERO to develop modifications to standard BAL002-2 to address their concerns regarding the 15-minute recovery period set forth in Requirement R1. In
the order, FERC stated:
“Accordingly, we direct NERC to develop modifications to Reliability Standard BAL-002-2,
Requirement R1 to require Balancing Authorities (BA) or Reserve Sharing Groups (RSG): (1) to
notify the reliability coordinator of the conditions set forth in Requirement R1, Part 1.3.1
preventing it from complying with the 15-minute ACE recovery period; and (2) to provide the
reliability coordinator with its ACE recovery plan, including a target recovery time. NERC may also
propose an equally efficient and effective alternative.”
Please provide your responses to the questions listed below along with any detailed comments.
Questions
1. The SDTs execution of this Standards Authorization Request (SAR) requires the SDT to address the
FERC Order directives or alternatively propose modifications that address the Commission
concerns in the FERC Order. This SAR will specifically address revising BAL-002-2 to require that
BAs and RSGs: (1) notify the Reliability Coordinator that the BA or RSG cannot comply with the 15minute ACE recovery period due to existence of the conditions as set forth in Requirement R1, Part
1.3.1; and (2) provide the Reliability Coordinator with an ACE recovery plan that includes a target
recovery time. Do you agree with this proposed revision? If not, please provide specific language
on the proposed revision.
Yes
No
Comments:
2. Based on the scope of the SAR, do you have any other comments for drafting team consideration?
Yes
No
Comments:
Unofficial Comment Form
Project 2017-06 Modifications to BAL-002-2 | June 2017
2
Standards Announcement
Project 2017-06 Modifications to BAL-002-2
Standards Authorization Request
Informal Comment Period Open through July 20, 2017
Now Available
A 30-day informal comment period on the Standards Authorization Request (SAR) for BAL-002-2
Disturbance Control Standard—Contingency Reserve for Recovery from a Balancing Contingency
Event, is open through 8 p.m. Eastern, Thursday, July 20, 2017.
Commenting
Use the electronic form to submit comments on the SAR. If you experience any difficulties using the
electronic form, contact Wendy Muller. An unofficial Word version of the comment form is posted on
the project page.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 5 p.m. Eastern).
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
The drafting team will review all responses received during the comment period and determine the next
steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Darrel Richardson (via email), or
at (609) 613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Comment Report
Project Name:
2017-06 Modifications to BAL-002-2 | Standards Authorization Request
Comment Period Start Date:
6/20/2017
Comment Period End Date:
7/20/2017
Associated Ballots:
There were 21 sets of responses, including comments from approximately 72 different people from approximately 48 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
Questions
1. The SDTs execution of this Standards Authorization Request (SAR) requires the SDT to address the FERC Order directives or alternatively
propose modifications that address the Commission concerns in the FERC Order. This SAR will specifically address revising BAL-002-2 to
require that BAs and RSGs: (1) notify the Reliability Coordinator that the BA or RSG cannot comply with the 15-minute ACE recovery period
due to existence of the conditions as set forth in Requirement R1, Part 1.3.1; and (2) provide the Reliability Coordinator with an ACE recovery
plan that includes a target recovery time. Do you agree with this proposed revision? If not, please provide specific language on the
proposed revision.
2. Based on the scope of the SAR, do you have any other comments for drafting team consideration?
Organization
Name
ACES Power
Marketing
Duke Energy
Seattle City
Light
Name
Brian Van
Gheem
Segment(s)
6
Colby Bellville 1,3,5,6
Ginette
Lacasse
1,3,4,5,6
Region
NA - Not
Applicable
Group Name
ACES
Greg Froehling
Standards
Collaborators
FRCC,RF,SERC Duke Energy
WECC
Group Member
Name
Seattle City
Light Ballot
Body
Group
Member
Organization
Group
Member
Segment(s)
Group Member
Region
Rayburn
Country
Electric
Cooperative,
Inc.
3
SPP RE
Bob Solomon
Hoosier
Energy Rural
Electric
Cooperative,
Inc.
1
RF
Michael
Brytowski
Great River
Energy
1,3,5,6
MRO
Karl Kohlrus
Prairie Power, 1,3
Inc.
SERC
Mark Ringhausen Old Dominion 3,4
Electric
Cooperative
SERC
Doug Hils
Duke Energy
1
RF
Lee Schuster
Duke Energy
3
FRCC
Dale Goodwine
Duke Energy
5
SERC
Greg Cecil
Duke Energy
6
RF
Pawel Krupa
Seattle City
Light
1
WECC
Hao Li
Seattle City
Light
4
WECC
Bud (Charles)
Freeman
Seattle City
Light
6
WECC
Mike Haynes
Seattle City
Light
5
WECC
Michael Watkins
Seattle City
Light
1,4
WECC
Faz Kasraie
Seattle City
Light
5
WECC
John Clark
Seattle City
Light
6
WECC
Tuan Tran
Seattle City
Light
3
WECC
Laurrie Hammack Seattle City
Light
3
WECC
Northeast
Power
Coordinating
Council
Ruida Shu
1,2,3,4,5,6,7,8,9,10 NPCC
RSC
Paul Malozewski Hydro One.
1
NPCC
Guy Zito
Northeast
Power
Coordinating
Council
NA - Not
Applicable
NPCC
Randy
MacDonald
New
Brunswick
Power
2
NPCC
Wayne Sipperly
New York
Power
Authority
4
NPCC
Glen Smith
Entergy
Services
4
NPCC
Brian Robinson
Utility
Services
5
NPCC
Bruce Metruck
New York
Power
Authority
6
NPCC
Alan Adamson
New York
State
Reliability
Council
7
NPCC
Edward Bedder
Orange &
Rockland
Utilities
1
NPCC
David Burke
Orange &
Rockland
Utilities
3
NPCC
Michele Tondalo
UI
1
NPCC
Sylvain Clermont Hydro Quebec 1
NPCC
Si Truc Phan
Hydro Quebec 2
NPCC
Helen Lainis
IESO
2
NPCC
Laura Mcleod
NB Power
1
NPCC
Michael Forte
Con Edison
1
NPCC
Kelly Silver
Con Edison
3
NPCC
Peter Yost
Con Edison
4
NPCC
Brian O'Boyle
Con Edison
5
NPCC
Michael
Schiavone
National Grid
1
NPCC
Michael Jones
National Grid
3
NPCC
Southwest
Power Pool,
Inc. (RTO)
Shannon
Mickens
PPL Shelby Wade
Louisville Gas
and Electric
Co.
2
1,3,5,6
SPP RE
RF,SERC
David
Ramkalawan
Ontario Power 5
Generation
Inc.
NPCC
Quintin Lee
Eversource
Energy
1
NPCC
Kathleen
Goodman
ISO-NE
2
NPCC
Greg Campoli
NYISO
2
NPCC
Silvia Mitchell
NextEra
6
Energy Florida Power
and Light Co.
NPCC
Sean Bodkin
Dominion Dominion
Resources,
Inc.
6
NPCC
SPP
Shannon Mickens Southwest
Standards
Power Pool
Inc.
Review Group
2
SPP RE
PPL NERC
Registered
Affiliates
Lonnie
Lindekugel
Southwest
Power Pool
Inc.
2
SPP RE
Mahmood Safi
Omaha Public 5
Power District
SPP RE
Charlie Freibert
LG&E and KU 3
Energy, LLC
SERC
Brenda Truhe
PPL Electric
Utilities
Corporation
RF
Dan Wilson
LG&E and KU 5
Energy, LLC
SERC
Linn Oelker
LG&E and KU 6
Energy, LLC
SERC
1
1. The SDTs execution of this Standards Authorization Request (SAR) requires the SDT to address the FERC Order directives or alternatively
propose modifications that address the Commission concerns in the FERC Order. This SAR will specifically address revising BAL-002-2 to
require that BAs and RSGs: (1) notify the Reliability Coordinator that the BA or RSG cannot comply with the 15-minute ACE recovery period
due to existence of the conditions as set forth in Requirement R1, Part 1.3.1; and (2) provide the Reliability Coordinator with an ACE recovery
plan that includes a target recovery time. Do you agree with this proposed revision? If not, please provide specific language on the
proposed revision.
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer
No
Document Name
Comment
Currently there is no requirement for a Reserve Sharing Group to have a 24 hour, manned, operations center. This would be required if this proposal is
implemented. Furthermore, it would also require the Reserve Sharing Group to have authority in some manner over the participating BAs to devise and
implement a recovery plan. A proposed alternative could be that BAs that are a part of a RSG must notify their RC if they will not be able to recover their
individual ACE in the recovery period as well as providing their recovery plan and target recovery time.
Likes
0
Dislikes
0
Response
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer
No
Document Name
Comment
Please see response to Queston #2.
Likes
0
Dislikes
0
Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
Document Name
Comment
No
The Cityy Light subjet amtter expert feels that there should be no requirement that forces a Reserve Sharing Group to have a 24 hour a day operations
center. An alternative would be for BA’s that are part of an RSG and cause the RSG to be in a disturbance provide the Reliability Coordinator with an
ACE recovery plan if they will not be able to recover their ACE in 15 minutes.
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
No
Document Name
Comment
The SPP Standards Review Group recommends that the drafting team provides clarity on what the FERC Order is requiring and the situation that has
been identified in Requirement R1 Part 1.3.1 of the Standard. From our perspective, there may be some confusion on what goals that need to be
accomplished for a Responsible Entity pertaining to this requirement. It’s not clear on if a the event drives the situation in to 1.3.1 or b has the EEA
Event already occurred and then the Responsible Entity needs to notify the RC about not meeting their recovery time as well as submitting a Recovery
Plan. Also, we recommend that if the FERC Order addresses a then BAL-002-2 may be the appropriate document to conduct the proposed revisions.
However, if the concerns are more applicable to b then the group would recommend making the appropriate revisions to the EOP-011-1 Standard.
Likes
0
Dislikes
0
Response
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer
No
Document Name
Comment
We caution the use of “15-minute ACE recovery period” in the SAR. We believe the SDT should have clear direction to instead leverage the previously
NERC Glossary-defined term, “Contingency Event Recovery Period.” This term is referenced frequently within the standard and aligns with the efforts
of the previous Standard Drafting Team.
Likes
0
Dislikes
0
Response
Dori Quam - NorthWestern Energy - 1 - WECC
Answer
Yes
Document Name
Comment
In its comments to FERC’s Notice of Proposed Rulemaking (NOPR) in Docket No. RM16-7-000, Arizona Public Service Company (APS) outlined a
proposal regarding notice to the RC when the extenuating conditions listed in Requirement R1.3.1 are met and the BA is unable to recover its ACE
within the 15-minute recovery period. This proposal addressed FERC’s concerns with extension of the 15-minute ACE recovery period, but also allowed
appropriate flexibility to BAs when extenuating circumstances are present. (Order No. 835, P 36.)
NorthWestern Energy agrees with the proposal that was outlined by APS in its comments to the FERC NOPR. (APS Comments, Accession No.
20160720-2146, Section II-A, pages 3–9.)
Likes
0
Dislikes
0
Response
John Williams - Tallahassee Electric (City of Tallahassee, FL) - 1,3,5
Answer
Yes
Document Name
Comment
Likes
1
Dislikes
Tallahassee Electric (City of Tallahassee, FL), 1, Langston Scott
0
Response
Leonard Kula - Independent Electricity System Operator - 2
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
sean erickson - Western Area Power Administration - 1,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Kasey Bohannon - APS - Arizona Public Service Co. - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Mike Smith - Manitoba Hydro - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Response
2. Based on the scope of the SAR, do you have any other comments for drafting team consideration?
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer
No
Document Name
Comment
We thank you for this opportunity to provide these comments.
Likes
0
Dislikes
0
Response
Dori Quam - NorthWestern Energy - 1 - WECC
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Ginette Lacasse - Seattle City Light - 1,3,4,5,6 - WECC, Group Name Seattle City Light Ballot Body
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Mike Smith - Manitoba Hydro - 1,3,5,6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
No
Document Name
Comment
Likes
Dislikes
0
0
Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 3,5,6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Kasey Bohannon - APS - Arizona Public Service Co. - 1,3,5,6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
sean erickson - Western Area Power Administration - 1,6
Answer
Document Name
No
Comment
Likes
0
Dislikes
0
Response
Leonard Kula - Independent Electricity System Operator - 2
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
John Williams - Tallahassee Electric (City of Tallahassee, FL) - 1,3,5
Answer
No
Document Name
Comment
Likes
1
Dislikes
Response
Tallahassee Electric (City of Tallahassee, FL), 1, Langston Scott
0
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer
Yes
Document Name
Comment
The IRC Standards Review Committee (SRC) provides these comments: As one of the “alternative modifications” the SRC proposes the SDT consider
converting the Standard to a communication guide (developed under the auspices of the NERC OC) that could be converted to a standard if such a
need were identified by the RCs.
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
The SPP Standards Review Group recommends that the drafting team evaluate the expansion of SAR that are associated with part 1.3.2 of the
Standard. Our concern pertains to contingencies impacting frequency that is outside of the Responsible Entity’s area that has a significant impact on the
Responsible Entity meeting the 15 minute recovery.
Likes
0
Dislikes
0
Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Duke Energy agrees that the SAR aligns with the directive from FERC, and also agrees with the scope of this project as written currently.
Likes
0
Dislikes
Response
0
Scott Downey - Peak Reliability - 1
Answer
Yes
Document Name
Comment
Peak appreciates the opportunity to provide comments on the BAL-002-2 SAR. Peak requests consideration be given to intended and/or unintended
expectations resulting from the provision of the information to the Reliability Coordinator that may or may not be covered by additional NERC Reliability
Standards.
Likes
0
Dislikes
0
Response
Shelby Wade - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF, Group Name PPL NERC Registered Affiliates
Answer
Yes
Document Name
Comment
“The objective of this SAR is to provide clear, unambiguous requirements to address the directives in the January 19, 2017 FERC Order regarding the
recovery from a Balancing Contingency Event, or alternatively propose modifications that address the Commission concerns.”
Since BAL-002-2 is addressing recovery from a Reportable Balancing Contingency Event (as distinct from a separately defined [non-reportable]
Balancing Contingency Event), and since the FERC Order requires NERC to develop modifications regarding such Reportable events, in order to avoid
any ambiguity or confusion we recommend that the SAR Objective be revised to state:
“The objective of this SAR is to provide clear, unambiguous requirements to address the directives in the January 19, 2017 FERC Order regarding the
recovery from a Reportable Balancing Contingency Event, or alternatively propose modifications that address the Commission concerns.”
Likes
0
Dislikes
0
Response
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer
Document Name
Yes
Comment
PacifiCorp is concerned that (1) the requirement to notify the reliability coordinator of the conditions set forth in Requirement R1, Part 1.3.1 preventing it
from complying with the 15-minute ACE recovery period; and (2) to provide the reliability coordinator with its ACE recovery plan, including a target
recovery time, will be distracting requirements as the balancing area operators are working towards recovery in the 15-minute period. Setting aside
recovering from the event to provide notification to the reliability coordinator could impede efforts towards the recovery itself. We fail to see the value in
these additional requirements and wonder if is this more suitable for the Eastern Interconnection – Western Interconnection power pool agencies are
not 7x24 shops.
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
In order to provide clear, unambiguous requirements to address the FERC directive, Texas RE recommends the standard drafting team (SDT) consider
specifying a time-frame in which the notification and provision of a recovery plan is expected to occur. Developing a recovery plan and target recovery
time may not be feasible within 15 minutes, so it may be more practical to require notification to the Reliability Coordinator (RC) within 15 minutes of the
event, and provision of a recovery plan within an agreed upon time-frame.
Likes
0
Dislikes
Response
0
Consideration of Comments
Project Name:
2017‐06 Modifications to BAL‐002‐2 | Standards Authorization Request
Comment Period Start Date:
6/20/2017
Comment Period End Date:
7/20/2017
Associated Ballots:
There were 21 sets of responses, including comments from approximately 72 different people from approximately 48 companies
representing the 10 Industry Segments as shown in the table on the following pages.
Questions
1. The SDTs execution of this Standards Authorization Request (SAR) requires the SDT to address the FERC Order directives or
alternatively propose modifications that address the Commission concerns in the FERC Order. This SAR will specifically address
revising BAL‐002‐2 to require that BAs and RSGs: (1) notify the Reliability Coordinator that the BA or RSG cannot comply with the 15‐
minute ACE recovery period due to existence of the conditions as set forth in Requirement R1, Part 1.3.1; and (2) provide the
Reliability Coordinator with an ACE recovery plan that includes a target recovery time. Do you agree with this proposed revision? If
not, please provide specific language on the proposed revision.
2. Based on the scope of the SAR, do you have any other comments for drafting team consideration?
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
2
Organization
Name
Name
ACES Power Brian Van
Marketing Gheem
Segment(s)
6
Duke Energy Colby Bellville 1,3,5,6
Region
NA ‐ Not
Applicable
Group Name
Group Member
Name
ACES
Greg Froehling
Standards
Collaborators
Rayburn
3
Country
Electric
Cooperative,
Inc.
SPP RE
Bob Solomon
Hoosier
1
Energy Rural
Electric
Cooperative,
Inc.
RF
Michael
Brytowski
Great River
Energy
1,3,5,6
MRO
Karl Kohlrus
Prairie
Power, Inc.
1,3
SERC
Mark
Ringhausen
Old
3,4
Dominion
Electric
Cooperative
SERC
Duke Energy 1
RF
Duke Energy 3
FRCC
Dale Goodwine Duke Energy 5
SERC
Greg Cecil
Duke Energy 6
RF
Pawel Krupa
Seattle City 1
Light
WECC
FRCC,RF,SERC Duke Energy Doug Hils
Lee Schuster
Seattle City Ginette
Light
Lacasse
1,3,4,5,6
WECC
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
3
Organization
Name
Name
Segment(s)
Region
Group Name
Seattle City
Light Ballot
Body
Northeast
Ruida Shu
Power
Coordinating
Council
1,2,3,4,5,6,7,8,9,10 NPCC
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
RSC
Group Member
Name
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
Hao Li
Seattle City 4
Light
WECC
Bud (Charles)
Freeman
Seattle City 6
Light
WECC
Mike Haynes
Seattle City 5
Light
WECC
Michael Watkins Seattle City 1,4
Light
WECC
Faz Kasraie
Seattle City 5
Light
WECC
John Clark
Seattle City 6
Light
WECC
Tuan Tran
Seattle City 3
Light
WECC
Laurrie
Hammack
Seattle City 3
Light
WECC
Paul Malozewski Hydro One. 1
NPCC
Guy Zito
Northeast
NA ‐ Not
Power
Applicable
Coordinating
Council
NPCC
Randy
MacDonald
New
Brunswick
Power
NPCC
2
4
Organization
Name
Name
Segment(s)
Region
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
Group Name
Group Member
Name
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
Wayne Sipperly New York
Power
Authority
4
NPCC
Glen Smith
Entergy
Services
4
NPCC
Brian Robinson Utility
Services
5
NPCC
Bruce Metruck
New York
Power
Authority
6
NPCC
Alan Adamson
New York
State
Reliability
Council
7
NPCC
Edward Bedder Orange &
Rockland
Utilities
1
NPCC
David Burke
3
NPCC
Michele Tondalo UI
1
NPCC
Sylvain Clermont Hydro
Quebec
1
NPCC
Orange &
Rockland
Utilities
5
Organization
Name
Name
Segment(s)
Region
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
Group Name
Group Member
Name
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
Si Truc Phan
Hydro
Quebec
2
NPCC
Helen Lainis
IESO
2
NPCC
Laura Mcleod
NB Power
1
NPCC
Michael Forte
Con Edison
1
NPCC
Kelly Silver
Con Edison
3
NPCC
Peter Yost
Con Edison
4
NPCC
Brian O'Boyle
Con Edison
5
NPCC
Michael
Schiavone
National Grid 1
NPCC
Michael Jones
National Grid 3
NPCC
David
Ramkalawan
Ontario
Power
Generation
Inc.
5
NPCC
Quintin Lee
Eversource
Energy
1
NPCC
Kathleen
Goodman
ISO‐NE
2
NPCC
Greg Campoli
NYISO
2
NPCC
Silvia Mitchell
NextEra
Energy ‐
Florida
6
NPCC
6
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member
Name
Group
Group
Group Member
Member
Member
Region
Organization Segment(s)
Power and
Light Co.
Southwest Shannon
Power Pool, Mickens
Inc. (RTO)
2
PPL ‐
Shelby Wade 1,3,5,6
Louisville Gas
and Electric
Co.
SPP RE
RF,SERC
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
SPP
Standards
Review
Group
PPL NERC
Registered
Affiliates
Sean Bodkin
Dominion ‐
Dominion
Resources,
Inc.
6
NPCC
Shannon
Mickens
Southwest 2
Power Pool
Inc.
SPP RE
Lonnie
Lindekugel
Southwest 2
Power Pool
Inc.
SPP RE
Mahmood Safi
Omaha
5
Public Power
District
SPP RE
Charlie Freibert LG&E and KU 3
Energy, LLC
SERC
Brenda Truhe
PPL Electric 1
Utilities
Corporation
RF
Dan Wilson
LG&E and KU 5
Energy, LLC
SERC
Linn Oelker
LG&E and KU 6
Energy, LLC
SERC
7
1. The SDTs execution of this Standards Authorization Request (SAR) requires the SDT to address the FERC Order directives or
alternatively propose modifications that address the Commission concerns in the FERC Order. This SAR will specifically address revising
BAL‐002‐2 to require that BAs and RSGs: (1) notify the Reliability Coordinator that the BA or RSG cannot comply with the 15‐minute
ACE recovery period due to existence of the conditions as set forth in Requirement R1, Part 1.3.1; and (2) provide the Reliability
Coordinator with an ACE recovery plan that includes a target recovery time. Do you agree with this proposed revision? If not, please
provide specific language on the proposed revision.
John Merrell ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 1,3,4,5,6
Answer
No
Document Name
Comment
Currently there is no requirement for a Reserve Sharing Group to have a 24 hour, manned, operations center. This would be required if
this proposal is implemented. Furthermore, it would also require the Reserve Sharing Group to have authority in some manner over the
participating BAs to devise and implement a recovery plan. A proposed alternative could be that BAs that are a part of a RSG must notify
their RC if they will not be able to recover their individual ACE in the recovery period as well as providing their recovery plan and target
recovery time.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SAR DT understands and agrees with your concern. The SAR DT will recommend to the SDT to modify
the language to provide clarity to Requirement R1 Part 1.3.1 with respect to the responsible entity communicating with the RC.
Sandra Shaffer ‐ Berkshire Hathaway ‐ PacifiCorp ‐ 6
Answer
No
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
8
Document Name
Comment
Please see response to Queston #2.
Likes 0
Dislikes 0
Response
Ginette Lacasse ‐ Seattle City Light ‐ 1,3,4,5,6 ‐ WECC, Group Name Seattle City Light Ballot Body
Answer
No
Document Name
Comment
The Cityy Light subjet amtter expert feels that there should be no requirement that forces a Reserve Sharing Group to have a 24 hour a
day operations center. An alternative would be for BA’s that are part of an RSG and cause the RSG to be in a disturbance provide the
Reliability Coordinator with an ACE recovery plan if they will not be able to recover their ACE in 15 minutes.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SAR DT understands and agrees with your concern. The SAR DT will recommend to the SDT to modify
the language to provide clarity to Requirement R1 Part 1.3.1.
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
No
Document Name
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
9
Comment
The SPP Standards Review Group recommends that the drafting team provides clarity on what the FERC Order is requiring and the
situation that has been identified in Requirement R1 Part 1.3.1 of the Standard. From our perspective, there may be some confusion on
what goals that need to be accomplished for a Responsible Entity pertaining to this requirement. It’s not clear on if a the event drives the
situation in to 1.3.1 or b has the EEA Event already occurred and then the Responsible Entity needs to notify the RC about not meeting
their recovery time as well as submitting a Recovery Plan. Also, we recommend that if the FERC Order addresses a then BAL‐002‐2 may be
the appropriate document to conduct the proposed revisions. However, if the concerns are more applicable to b then the group would
recommend making the appropriate revisions to the EOP‐011‐1 Standard.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SAR DT understands and agrees with your concern. The SAR DT will recommend to the SDT to modify
the language to provide clarity to Requirement R1 Part 1.3.1.
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
Answer
No
Document Name
Comment
We caution the use of “15‐minute ACE recovery period” in the SAR. We believe the SDT should have clear direction to instead leverage
the previously NERC Glossary‐defined term, “Contingency Event Recovery Period.” This term is referenced frequently within the standard
and aligns with the efforts of the previous Standard Drafting Team.
Likes 0
Dislikes 0
Response
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
10
Thank you for your comment. The SAR DT agrees that defined terms should be used within the standard.
Dori Quam ‐ NorthWestern Energy ‐ 1 ‐ WECC
Answer
Yes
Document Name
Comment
In its comments to FERC’s Notice of Proposed Rulemaking (NOPR) in Docket No. RM16‐7‐000, Arizona Public Service Company (APS)
outlined a proposal regarding notice to the RC when the extenuating conditions listed in Requirement R1.3.1 are met and the BA is unable
to recover its ACE within the 15‐minute recovery period. This proposal addressed FERC’s concerns with extension of the 15‐minute ACE
recovery period, but also allowed appropriate flexibility to BAs when extenuating circumstances are present. (Order No. 835, P 36.)
NorthWestern Energy agrees with the proposal that was outlined by APS in its comments to the FERC NOPR. (APS Comments, Accession
No. 20160720‐2146, Section II‐A, pages 3–9.)
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT will consider this information when developing modifications to the standard.
John Williams ‐ Tallahassee Electric (City of Tallahassee, FL) ‐ 1,3,5
Answer
Yes
Document Name
Comment
Likes 1
Tallahassee Electric (City of Tallahassee, FL), 1, Langston Scott
Dislikes 0
Response
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
11
Leonard Kula ‐ Independent Electricity System Operator ‐ 2
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
sean erickson ‐ Western Area Power Administration ‐ 1,6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
12
Likes 0
Dislikes 0
Response
Kasey Bohannon ‐ APS ‐ Arizona Public Service Co. ‐ 1,3,5,6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Sean Bodkin ‐ Dominion ‐ Dominion Resources, Inc. ‐ 3,5,6
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
13
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Amy Casuscelli ‐ Xcel Energy, Inc. ‐ 1,3,5,6 ‐ MRO,WECC,SPP RE
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Mike Smith ‐ Manitoba Hydro ‐ 1,3,5,6
Answer
Yes
Document Name
Comment
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
14
Likes 0
Dislikes 0
Response
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Colby Bellville ‐ Duke Energy ‐ 1,3,5,6 ‐ FRCC,SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7,8,9,10 ‐ NPCC, Group Name RSC
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
15
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
16
2. Based on the scope of the SAR, do you have any other comments for drafting team consideration?
Brian Van Gheem ‐ ACES Power Marketing ‐ 6 ‐ NA ‐ Not Applicable, Group Name ACES Standards Collaborators
Answer
No
Document Name
Comment
We thank you for this opportunity to provide these comments.
Likes 0
Dislikes 0
Response
Dori Quam ‐ NorthWestern Energy ‐ 1 ‐ WECC
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7,8,9,10 ‐ NPCC, Group Name RSC
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
17
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Ginette Lacasse ‐ Seattle City Light ‐ 1,3,4,5,6 ‐ WECC, Group Name Seattle City Light Ballot Body
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Mike Smith ‐ Manitoba Hydro ‐ 1,3,5,6
Answer
No
Document Name
Comment
Likes 0
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
18
Dislikes 0
Response
Amy Casuscelli ‐ Xcel Energy, Inc. ‐ 1,3,5,6 ‐ MRO,WECC,SPP RE
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Sean Bodkin ‐ Dominion ‐ Dominion Resources, Inc. ‐ 3,5,6
Answer
No
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
19
Document Name
Comment
Likes 0
Dislikes 0
Response
Kasey Bohannon ‐ APS ‐ Arizona Public Service Co. ‐ 1,3,5,6
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
20
Response
sean erickson ‐ Western Area Power Administration ‐ 1,6
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Leonard Kula ‐ Independent Electricity System Operator ‐ 2
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
John Merrell ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 1,3,4,5,6
Answer
No
Document Name
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
21
Comment
Likes 0
Dislikes 0
Response
John Williams ‐ Tallahassee Electric (City of Tallahassee, FL) ‐ 1,3,5
Answer
No
Document Name
Comment
Likes 1
Tallahassee Electric (City of Tallahassee, FL), 1, Langston Scott
Dislikes 0
Response
Elizabeth Axson ‐ Electric Reliability Council of Texas, Inc. ‐ 2
Answer
Yes
Document Name
Comment
The IRC Standards Review Committee (SRC) provides these comments: As one of the “alternative modifications” the SRC proposes the
SDT consider converting the Standard to a communication guide (developed under the auspices of the NERC OC) that could be converted
to a standard if such a need were identified by the RCs.
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
22
Likes 0
Dislikes 0
Response
Thank you for your comment. The SAR DT is unsure as to the issue you are raising. However, if you are proposing a communication guide
instead of this SAR, the SAR DT believes that there is still clarity necessary to resolve the ambiguity highlighted in Requirement R1 Part
1.3.1 and to address the FERC order. In addition, the SAR DT will recommend to the NERC OC to review the existing Operating Reserve
Management Guideline to ensure the communication issues are considered.
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
The SPP Standards Review Group recommends that the drafting team evaluate the expansion of SAR that are associated with part 1.3.2 of
the Standard. Our concern pertains to contingencies impacting frequency that is outside of the Responsible Entity’s area that has a
significant impact on the Responsible Entity meeting the 15 minute recovery.
Likes 0
Dislikes 0
Response
Thank you for your comment. The scope of this SAR is explicitly and exclusively addressing the FERC Order directives. However, if you
believe additional modifications are necessary, you may submit a SAR that addresses your concerns.
Colby Bellville ‐ Duke Energy ‐ 1,3,5,6 ‐ FRCC,SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
23
Duke Energy agrees that the SAR aligns with the directive from FERC, and also agrees with the scope of this project as written currently.
Likes 0
Dislikes 0
Response
Thank you for your affirmative response and clarifying comment.
Scott Downey ‐ Peak Reliability ‐ 1
Answer
Yes
Document Name
Comment
Peak appreciates the opportunity to provide comments on the BAL‐002‐2 SAR. Peak requests consideration be given to intended and/or
unintended expectations resulting from the provision of the information to the Reliability Coordinator that may or may not be covered by
additional NERC Reliability Standards.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SAR DT understands your concern and will recommend to the SDT that it consider potentially affected
standards.
Shelby Wade ‐ PPL ‐ Louisville Gas and Electric Co. ‐ 1,3,5,6 ‐ SERC,RF, Group Name PPL NERC Registered Affiliates
Answer
Yes
Document Name
Comment
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
24
“The objective of this SAR is to provide clear, unambiguous requirements to address the directives in the January 19, 2017 FERC Order
regarding the recovery from a Balancing Contingency Event, or alternatively propose modifications that address the Commission
concerns.”
Since BAL‐002‐2 is addressing recovery from a Reportable Balancing Contingency Event (as distinct from a separately defined [non‐
reportable] Balancing Contingency Event), and since the FERC Order requires NERC to develop modifications regarding such Reportable
events, in order to avoid any ambiguity or confusion we recommend that the SAR Objective be revised to state:
“The objective of this SAR is to provide clear, unambiguous requirements to address the directives in the January 19, 2017 FERC Order
regarding the recovery from a Reportable Balancing Contingency Event, or alternatively propose modifications that address the
Commission concerns.”
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDTs are instructed to develop clear and unambiguous language in the standard and therefore, no
modifications to the SAR are necessary.
Sandra Shaffer ‐ Berkshire Hathaway ‐ PacifiCorp ‐ 6
Answer
Yes
Document Name
Comment
PacifiCorp is concerned that (1) the requirement to notify the reliability coordinator of the conditions set forth in Requirement R1, Part
1.3.1 preventing it from complying with the 15‐minute ACE recovery period; and (2) to provide the reliability coordinator with its ACE
recovery plan, including a target recovery time, will be distracting requirements as the balancing area operators are working towards
recovery in the 15‐minute period. Setting aside recovering from the event to provide notification to the reliability coordinator could
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
25
impede efforts towards the recovery itself. We fail to see the value in these additional requirements and wonder if is this more suitable
for the Eastern Interconnection – Western Interconnection power pool agencies are not 7x24 shops.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SAR DT understands and agrees with your concern. The SAR DT will recommend to the SDT to modify
the language to provide clarity to Requirement R1 Part 1.3.1 with respect to the responsible entity, the BA, communicating with the RC.
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
Document Name
Comment
In order to provide clear, unambiguous requirements to address the FERC directive, Texas RE recommends the standard drafting team
(SDT) consider specifying a time‐frame in which the notification and provision of a recovery plan is expected to occur. Developing a
recovery plan and target recovery time may not be feasible within 15 minutes, so it may be more practical to require notification to the
Reliability Coordinator (RC) within 15 minutes of the event, and provision of a recovery plan within an agreed upon time‐frame.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT will consider your comments while developing the language to address the directives from the
FERC Order.
End of Report
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2 SAR
Enter Date C of C will be posted here:
26
Unofficial Nomination Form
Project 2017-06 Modifications to BAL-002-2
Standards Authorization Request Drafting Team
Do not use this form for submitting nominations. Use the electronic form to submit nominations by 8
p.m. Eastern, Wednesday, August 9, 2017. This unofficial version is provided to assist nominees in
compiling the information necessary to submit the electronic form.
Additional information about this project is available on the Project 2017-06 Modifications to BAL-002-2
page. If you have questions, contact Senior Standards Developer Darrel Richardson, (via email), or at
(609) 613-1848.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
Previous drafting or periodic review team experience is beneficial, but not required. A brief
description of the desired qualifications, expected commitment, and other pertinent information is
included below.
Project 2017-06 Modifications to BAL-002-2
The primary goal of this SAR is to allow the standard drafting team (SDT) for Project 2017-06, Disturbance
Control to modify standard BAL-002-2 to address the directives of the January 19, 2017 FERC Order, and
to ensure consistency within the NERC body of Reliability Standards.
On January 19, 2017, FERC issued an order directing the ERO to develop modifications to standard BAL002-2 to address their concerns regarding the 15-minute recovery period set forth in Requirement R1. In
the order, FERC stated:
“Accordingly, we direct NERC to develop modifications to Reliability Standard BAL-002-2,
Requirement R1 to require Balancing Authorities (BA) or Reserve Sharing Groups (RSG): (1) to
notify the reliability coordinator of the conditions set forth in Requirement R1, Part 1.3.1
preventing it from complying with the 15-minute ACE recovery period; and (2) to provide the
reliability coordinator with its ACE recovery plan, including a target recovery time. NERC may also
propose an equally efficient and effective alternative.”
The time commitment for this project is expected to be up to two face-to-face meetings per quarter (on
average two full working days each meeting) with conference calls scheduled as needed to meet the
agreed-upon timeline the review or drafting team sets forth. Team members may also have side projects,
either individually or by subgroup, to present to the larger team for discussion and review. Lastly, an
important component of the review and drafting team effort is outreach. Members of the team will be
expected to conduct industry outreach during the development process to support a successful project
outcome.
We are seeking a cross section of the industry to participate on the team, but in particular are seeking
individuals who have experience and expertise in one or more of the following areas: Reliability
Coordinator operations, transmission operations, Balancing Authority operations and generation
operations. Experience with developing standards inside or outside (e.g., IEEE, NAESB, ANSI, etc.) of the
NERC process is beneficial, but is not required, and should be highlighted in the information submitted, if
applicable.
Individuals who have facilitation skills and experience and/or legal or technical writing backgrounds are
also strongly desired. Please include this in the description of qualifications as applicable.
Standards affected: BAL-002-2
Name:
Organization:
Address:
Telephone:
E-mail:
Please briefly describe your experience and qualifications to serve on the requested Standard
Drafting Team (Bio):
If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Unofficial Nomination Form
Project 2017-06 Modifications to BAL-002-2 | July-August 2017
2
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
Texas RE
FRCC
MRO
NPCC
RF
SERC
SPP RE
WECC
NA – Not Applicable
Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Select each Function 1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator
1
Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner
These functions are defined in the NERC Functional Model, which is available on the NERC web site.
Unofficial Nomination Form
Project 2017-06 Modifications to BAL-002-2 | July-August 2017
3
Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:
Name:
Telephone:
Organization:
E-mail:
Name:
Telephone:
Organization:
E-mail:
Provide the name and contact information of your immediate supervisor or a member of your
management who can confirm your organization’s willingness to support your active participation.
Name:
Telephone:
Title:
Email:
Unofficial Nomination Form
Project 2017-06 Modifications to BAL-002-2 | July-August 2017
4
Standards Announcement
Project 2017-06 Modifications to BAL-002-2
Supplemental Nomination Period Open through August 9, 2017
Now Available
Nominations are being sought for additional Standards Authorization Request drafting team
members through 8 p.m. Eastern, Wednesday, August 9, 2017. If you submitted a nomination
during the initial nomination period (June 20 through July 3, 2017), you do not need to resubmit
your nomination.
The nomination period is being reopened at the request of the Standards Committee (SC). There
was considerable overlap in the nominations received for this project and Project 2017-01
Modifications to BAL-003-1.1. The SC requested the additional nomination period to 1) reduce the
overlap between the two aforementioned projects; and, 2) increase the diversity within the two
drafting teams.
Use the electronic form to submit a nomination. If you experience any difficulties in using the
electronic form, contact Wendy Muller. An unofficial Word version of the nomination form is posted
on the Drafting Team Vacancies page and the project page.
Previous drafting or periodic review team experience is beneficial, but not required. See the project
page and unofficial nomination form for additional information.
Next Steps
The SC is expected to appoint members to the team September 2017. Nominees will be notified
shortly after they have been appointed.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance Senior Standards Developer, Darrel Richardson (via email), or at (609)
613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Authorization Request Form
When completed, please email this form to:
[email protected]
NERC welcomes suggestions to improve the
reliability of the bulk power system through
improved Reliability Standards. Please use this form
to submit your request to propose a new or a
revision to a NERC Reliability Standard.
Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard:
BAL‐002‐2 – Disturbance Control Standard—Contingency Reserve for
Recovery from a Balancing Contingency Event
Date Submitted:
SAR Requester Information
Name:
Darrel Richardson
Organization:
NERC Staff
Telephone:
609.613.1848
Email:
[email protected]
SAR Type (Check as many as applicable)
New Standard
Withdrawal of Existing Standard
Revision to Existing Standard
Urgent Action
SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
On January 19, 2017, FERC issued an order directing the ERO to develop modifications to standard BAL‐
002‐2 to address their concerns regarding the 15‐minute recovery period set forth in Requirement R1.
In the order, FERC stated:
“Accordingly, we direct NERC to develop modifications to Reliability Standard BAL‐002‐2, Requirement
R1 to require Balancing Authorities (BA) or Reserve Sharing Groups (RSG): (1) to notify the reliability
coordinator of the conditions set forth in Requirement R1, Part 1.3.1 preventing it from complying with
SAR Information
the 15‐minute ACE recovery period; and (2) to provide the reliability coordinator with its ACE recovery
plan, including a target recovery time. NERC may also propose an equally efficient and effective
alternative.” Disturbance Control Standard—Contingency Reserve for Recovery from a Balancing
Contingency Event Reliability Standard, 158 FERC ¶ 61,030 at P 37 (2017) (“FERC Order”). See also, id.,
at P 2 and PP 35‐36.
Purpose or Goal (How does this request propose to address the problem described above?):
The primary goal of this SAR is to allow the standard drafting team (SDT) for Project 2017‐06,
Disturbance Control to modify standard BAL‐002‐2 to address the directives of the January 19, 2017
FERC Order, and to ensure consistency within the NERC body of Reliability Standards.
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?):
The objective of this SAR is to provide clear, unambiguous requirements to address the directives in the
January 19, 2017 FERC Order regarding the recovery from a Balancing Contingency Event, or
alternatively propose modifications that address the Commission concerns.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The SDT shall modify the standard, Violation Risk Factors, Violation Severity Levels, and implementation
plan and shall work with compliance on an accompanying RSAW to address the FERC Order directives
described above.
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
The SDTs execution of this SAR requires the SDT to address the FERC Order directives described above
or alternatively propose modifications that address the Commission concerns in the FERC Order. This
SAR will specifically address either (A) revising BAL‐002‐2 to require that BAs and RSGs: (1) notify the
Reliability Coordinator that the BA or RSG cannot comply with the 15‐minute ACE recovery period due
to existence of the conditions as set forth in Requirement R1, Part 1.3.1; and (2) provide the Reliability
Coordinator with an ACE recovery plan that includes a target recovery time; or (B) proposing an equally
efficient and effective alternative.
Standards Authorization Request Form
2
Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Responsible for the real‐time operating reliability of its Reliability
Reliability Coordinator Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Integrates resource plans ahead of time, and maintains load‐
interchange‐resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.
Balancing Authority
Ensures communication of interchange transactions for reliability
Interchange Authority evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.
Planning Coordinator
Assesses the longer‐term reliability of its Planning Coordinator Area.
Resource Planner
Develops a one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission Planner
Develops a one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real‐time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution Provider
Delivers electrical energy to the end‐use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
Purchasing‐Selling
Entity
Purchases or sells energy, capacity, and necessary reliability‐related
services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Standards Authorization Request Form
3
Reliability Functions
Load‐Serving Entity
Secures energy and transmission service (and reliability‐related services)
to serve the end‐use customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall
be trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non‐sensitive information that is required for compliance
with reliability standards.
Enter
(yes/no)
Yes
Yes
Yes
Yes
Standards Authorization Request Form
4
Related Standards
Standard No.
Explanation
None
Related SARs
SAR ID
Explanation
None
Regional Variances
Region Explanation
ERCOT
None.
FRCC
None.
MRO
None.
NPCC
None.
RFC
None.
Standards Authorization Request Form
5
Regional Variances
SERC
None.
SPP
None.
WECC
None.
Version History
Version
Date
Owner
Change Tracking
1
June 3, 2013
Revised
1
August 29, 2014
Standards Information Staff Updated template
Standards Authorization Request Form
6
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the Board of Trustees.
Description of Current Draft
Completed Actions
SAR posted for comment
Anticipated Actions
Date
06/20/17 – 07/20/17
Date
45‐day formal comment period with initial ballot
February 2018 through
March 2018
10‐day final ballot
April 2018
NERC Board (Board) adoption
May 2018
Draft 1 – BAL‐002‐3
March 2018
Page 1 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
A. Introduction
1.
Title: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
2.
Number:
3.
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.
4.
Applicability:
4.1.
BAL‐002‐3
Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during which the
Balancing Authority is not in active status under the applicable
agreement or governing rules for the Reserve Sharing Group.
4.1.2. Reserve Sharing Group
5.
Effective Date: See the Implementation Plan for BAL‐002‐3.
B. Requirements and Measures
R1.
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
[Violation Risk Factor: High] [Time Horizon: Real‐time Operations]
1.1.
within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
zero (if its Pre‐Reporting Contingency Event ACE Value was positive or
equal to zero); however, any Balancing Contingency Event that occurs
during the Contingency Event Recovery Period shall reduce the required
recovery: (i) beginning at the time of, and (ii) by the magnitude of, such
individual Balancing Contingency Event,
or,
1.2.
Draft 1 – BAL‐002‐3
March 2018
its Pre‐Reporting Contingency Event ACE Value (if its Pre‐Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery
Period shall reduce the required recovery: (i) beginning at the time of, and
(ii) by the magnitude of, such individual Balancing Contingency Event.
document all Reportable Balancing Contingency Events using CR Form 1.
Page 2 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
1.3.
deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if the Responsible Entity:
1.3.1 is (i) a Balancing Authority or (ii) a Reserve Sharing Group with at least
one member that:
is experiencing a Reliability Coordinator declared Energy Emergency
Alert Level, and
is utilizing its Contingency Reserve to mitigate an operating
emergency in accordance with its emergency Operating Plan, and
has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency, and
has, during communications with its Reliability Coordinator in
accordance with the Energy Emergency Alert procedures, (i) notified
the Reliability Coordinator of the conditions described in the
preceding two bullet points preventing the Responsible Entity from
complying with Requirement R1 part 1.1, and (ii) provided the
Reliability Coordinator with an ACE recovery plan, including target
recovery time
or,
1.3.2 the Responsible Entity experiences:
multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or
multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.
M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.
R2. Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe Single
Contingency and make preparations to have Contingency Reserve equal to, or greater
than the Responsible Entity’s Most Severe Single Contingency available for
maintaining system reliability. [Violation Risk Factor: High] [Time Horizon: Operations
Planning]
Draft 1 – BAL‐002‐3
March 2018
Page 3 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
M2. Each Responsible Entity will have the following documentation to show compliance
with Requirement R2:
a dated Operating Process;
evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,
evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency and
that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.
R3. Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency, before
the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
Period resets the beginning of the Contingency Event Recovery Period. [Violation Risk
Factor: Medium] [Time Horizon: Real‐time Operations]
M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
C. Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity, or any
entity as otherwise designated by an Applicable Governmental Authority, in
their respective roles of monitoring and/or enforcing compliance with
mandatory and enforceable Reliability Standards in their respective
jurisdictions.
1.2.
Evidence Retention
The following evidence retention period(s) identify the period of time an entity
is required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full‐time period
since the last audit.
The Responsible Entity shall retain data or evidence to show compliance for the
current year, plus three previous calendar years, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
Draft 1 – BAL‐002‐3
March 2018
Page 4 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.3.
Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated Reliability Standard.
1.4.
Additional Compliance Information
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.
Draft 1 – BAL‐002‐3
March 2018
Page 5 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
Table of Compliance Elements
R#
R1.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Responsible Entity
achieved less than 100% but
at least 90% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period
The Responsible Entity
achieved less than 90% but
at least 80% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 80% but
at least 70% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 70% of
required recovery from a
Reportable Balancing
Contingency Event during
the Contingency Event
Recovery Period.
N/A
The Responsible Entity
developed an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to implement the
Operating Process.
The Responsible Entity failed
to develop an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency.
OR
The Responsible Entity failed
to use CR Form 1 to
document a Reportable
Balancing Contingency
Event.
R2.
The Responsible Entity
developed and implemented
an Operating Process to
determine its Most Severe
Single Contingency and to
have Contingency Reserve
equal to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to maintain
Draft 1 – BAL‐002‐3
March 2018
Page 6 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
annually the Operating
Process.
R3.
The Responsible Entity
restored less than 100% but
at least 90% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 90% but
at least 80% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 80% but
at least 70% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event during
the Contingency Event
Restoration Period.
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
CR Form 1
BAL‐002‐3 Rationales
Draft 1 – BAL‐002‐3
March 2018
Page 7 of 8
Supplemental Material
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from
Effective Date
Errata
0
February 14,
2006
Revised graph on page 3, “10
min.” to “Recovery time.”
Removed fourth bullet.
Errata
1
September 9,
2010
Filed petition for revisions to BAL‐
002 Version 1 with the
Commission
Revision
1
January 10, 2011 FERC letter ordered in Docket No.
RD10‐15‐00 approving BAL‐002‐1
1
April 1, 2012
Effective Date of BAL‐002‐1
1a
November 7,
2012
Interpretation adopted by the
NERC Board of Trustees
1a
February 12,
2013
Interpretation submitted to FERC
2
November 5,
2015
Adopted by NERC Board of
Trustees
Complete revision
2
January 19, 2017 FERC Order approved BAL‐002‐2.
Docket No. RM16‐7‐000
2
October 2, 2017
Draft 1 – BAL‐002‐3
March 2018
FERC letter Order issued
approving raising the VRF for
Requirement R1 and R2 from
Medium to High. Docket No.
RD17‐6‐000.
Page 8 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the Board of Trustees.
Description of Current Draft
Completed Actions
SAR posted for comment
Anticipated Actions
Date
06/20/17 – 07/20/17
Date
45‐day formal comment period with initial ballot
February 2018 through
March 2018
10‐day final ballot
April 2018
NERC Board (Board) adoption
May 2018
Draft 1 – BAL‐002‐3
March 2018
Page 1 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
A. Introduction
1.
Title: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
2.
Number:
3.
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.
4.
Applicability:
4.1.
BAL‐002‐32
Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during which the
Balancing Authority is not in active status under the applicable
agreement or governing rules for the Reserve Sharing Group.
4.1.2. Reserve Sharing Group
5.
Effective Date: See the Implementation Plan for BAL‐002‐32.
B. Requirements and Measures
R1.
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
[Violation Risk Factor: High] [Time Horizon: Real‐time Operations]
1.1.
within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
zero (if its Pre‐Reporting Contingency Event ACE Value was positive or
equal to zero); however, any Balancing Contingency Event that occurs
during the Contingency Event Recovery Period shall reduce the required
recovery: (i) beginning at the time of, and (ii) by the magnitude of, such
individual Balancing Contingency Event,
or,
1.2.
Draft 1 – BAL‐002‐3
March 2018
its Pre‐Reporting Contingency Event ACE Value (if its Pre‐Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery
Period shall reduce the required recovery: (i) beginning at the time of, and
(ii) by the magnitude of, such individual Balancing Contingency Event.
document all Reportable Balancing Contingency Events using CR Form 1.
Page 2 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
1.3.
deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if the Responsible Entity:
1.3.1 is (i) a Balancing Authority or (ii) a Reserve Sharing Group with at least
one member thatthe Responsible Entity:
is a Balancing Authority experiencing a Reliability Coordinator
declared Energy Emergency Alert Level or is a Reserve Sharing Group
whose member, or members, are experiencing a Reliability
Coordinator declared Energy Emergency Alert level, and
is utilizing its Contingency Reserve to mitigate an operating
emergency in accordance with its emergency Operating Plan, and
has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency, and
has, during communications with its Reliability Coordinator in
accordance with the Energy Emergency Alert procedures, (i) notified
the Reliability Coordinator of the conditions described in the
preceding two bullet points preventing the Responsible Entity from
complying with Requirement R1 part 1.1, and (ii) provided the
Reliability Coordinator with an ACE recovery plan, including target
recovery time
or,
1.3.2 the Responsible Entity experiences:
multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or
multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.
M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.
R2. Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe Single
Contingency and make preparations to have Contingency Reserve equal to, or greater
than the Responsible Entity’s Most Severe Single Contingency available for
maintaining system reliability. [Violation Risk Factor: High] [Time Horizon: Operations
Planning]
Draft 1 – BAL‐002‐3
March 2018
Page 3 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
M2. Each Responsible Entity will have the following documentation to show compliance
with Requirement R2:
a dated Operating Process;
evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,
evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency and
that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.
R3. Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency, before
the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
Period resets the beginning of the Contingency Event Recovery Period. [Violation Risk
Factor: Medium] [Time Horizon: Real‐time Operations]
M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
C. Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity, or any
entity as otherwise designated by an Applicable Governmental Authority, in
their respective roles of monitoring and/or enforcing compliance with
mandatory and enforceable Reliability Standards in their respective
jurisdictions.
1.2.
Evidence Retention
The following evidence retention period(s) identify the period of time an entity
is required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full‐time period
since the last audit.
The Responsible Entity shall retain data or evidence to show compliance for the
current year, plus three previous calendar years, unless directed by its
Draft 1 – BAL‐002‐3
March 2018
Page 4 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.3.
Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated Reliability Standard.
1.4.
Additional Compliance Information
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.
Draft 1 – BAL‐002‐3
March 2018
Page 5 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
Table of Compliance Elements
R#
R1.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Responsible Entity
achieved less than 100% but
at least 90% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period
The Responsible Entity
achieved less than 90% but
at least 80% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 80% but
at least 70% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 70% of
required recovery from a
Reportable Balancing
Contingency Event during
the Contingency Event
Recovery Period.
N/A
The Responsible Entity
developed an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to implement the
Operating Process.
The Responsible Entity failed
to develop an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency.
OR
The Responsible Entity failed
to use CR Form 1 to
document a Reportable
Balancing Contingency
Event.
R2.
The Responsible Entity
developed and implemented
an Operating Process to
determine its Most Severe
Single Contingency and to
have Contingency Reserve
equal to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to maintain
Draft 1 – BAL‐002‐3
March 2018
Page 6 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
annually the Operating
Process.
R3.
The Responsible Entity
restored less than 100% but
at least 90% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 90% but
at least 80% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 80% but
at least 70% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event during
the Contingency Event
Restoration Period.
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
BAL‐002‐2 Contingency Reserve for Recovery from a Balancing Contingency Event Background Document
CR Form 1
BAL‐002‐3 Rationales
Draft 1 – BAL‐002‐3
March 2018
Page 7 of 8
Supplemental Material
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from
Effective Date
Errata
0
February 14,
2006
Revised graph on page 3, “10
min.” to “Recovery time.”
Removed fourth bullet.
Errata
1
September 9,
2010
Filed petition for revisions to BAL‐
002 Version 1 with the
Commission
Revision
1
January 10, 2011 FERC letter ordered in Docket No.
RD10‐15‐00 approving BAL‐002‐1
1
April 1, 2012
Effective Date of BAL‐002‐1
1a
November 7,
2012
Interpretation adopted by the
NERC Board of Trustees
1a
February 12,
2013
Interpretation submitted to FERC
2
November 5,
2015
Adopted by NERC Board of
Trustees
Complete revision
2
January 19, 2017 FERC Order approved BAL‐002‐2.
Docket No. RM16‐7‐000
2
October 2, 2017
Draft 1 – BAL‐002‐3
March 2018
FERC letter Order issued
approving raising the VRF for
Requirement R1 and R2 from
Medium to High. Docket No.
RD17‐6‐000.
Page 8 of 8
Implementation Plan
Project 2017-06 Modifications to BAL-002-2
Requested Approvals
BAL‐002‐3 Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event
Requested Retirements
BAL‐002‐2 Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event
Applicable Entities
Balancing Authority
Reserve Sharing Group
Effective Date
The effective date for proposed Reliability Standard BAL‐002‐3 is provided below:
Where approval by an applicable governmental authority is required, Reliability Standard BAL‐002‐3
shall become effective the first day of the first calendar quarter that is six (6) calendar months after
the effective date of the applicable governmental authority’s order approving the standards and
terms, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, Reliability Standard BAL‐
002‐3 shall become effective on the first day of the first calendar quarter that is six (6) calendar
months after the date the standards and terms are adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.
Retirement Date
Current NERC Reliability Standards
The existing standard BAL‐002‐2 shall be retired immediately prior to the effective date of the
proposed BAL‐002‐3 standard.
Unofficial Comment Form
Project 2017-06 Modifications to BAL-002-2
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on Project 2017-06 Modifications to BAL-002-2. Comments must be submitted
by 8 p.m. Eastern, Monday, May 7, 2018.
Additional information is available on the project page. If you have questions, contact Principal Technical
Advisor, Darrel Richardson (via email) or at (609) 613-1848.
Background
On January 19, 2017, FERC issued an order directing the ERO to develop modifications to standard BAL002-2 to address their concerns regarding the 15-minute recovery period set forth in Requirement R1. In
the order, FERC stated:
“Accordingly, we direct NERC to develop modifications to Reliability Standard BAL-002-2,
Requirement R1 to require Balancing Authorities (BA) or Reserve Sharing Groups (RSG): (1) to
notify the reliability coordinator of the conditions set forth in Requirement R1, Part 1.3.1
preventing it from complying with the 15-minute ACE recovery period; and (2) to provide the
reliability coordinator with its ACE recovery plan, including a target recovery time. NERC may also
propose an equally efficient and effective alternative.”
Please provide your responses to the questions listed below along with any detailed comments.
Questions
1. The SDT has modified Requirement R1 to address the Commission’s concerns identified in FERC
Order 835. Do you agree that the proposed modifications clearly state the intentions of the SAR?
If not, please state your concerns and provide specific language on the proposed revision.
Yes
No
Comments:
2. Do you have any other comments for drafting team consideration?
Yes
No
Comments:
Rationales for BAL-002-3
February, 2018
Requirement R1
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
1.1. within the Contingency Event Recovery Period, demonstrate recovery by returning its
Reporting ACE to at least the recovery value of:
•
zero (if its Pre‐Reporting Contingency Event ACE Value was positive or equal to
zero); however, any Balancing Contingency Event that occurs during the Contingency Event
Recovery Period shall reduce the required recovery: (i) beginning at the time of, and (ii) by
the magnitude of, such individual Balancing Contingency Event,
or,
•
its Pre‐Reporting Contingency Event ACE Value (if its Pre‐Reporting Contingency
Event ACE Value was negative); however, any Balancing Contingency Event that occurs
during the Contingency Event Recovery Period shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, such individual Balancing
Contingency Event.
1.2.
document all Reportable Balancing Contingency Events using CR Form 1.
1.3. deploy Contingency Reserve, within system constraints, to respond to all Reportable
Balancing Contingency Events, however, it is not subject to compliance with Requirement R1 part
1.1 if the Responsible Entity:
1.3.1 is (i) a Balancing Authority or (ii) a Reserve Sharing Group with at least one member
that:
•
is a experiencing a Reliability Coordinator declared Energy Emergency Alert
Level, and
•
is utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan, and
•
has depleted its Contingency Reserve to a level below its Most Severe Single
Contingency, and
•
has, during communications with its Reliability Coordinator in accordance
with the Energy Emergency Alert procedures, (i) notified the Reliability Coordinator
of the conditions described in the preceding two bullet points preventing the
Responsible Entity from complying with Requirement R1 part 1.1, and (ii) provided
the Reliability Coordinator with an ACE recovery plan, including target recovery
time.
or,
1.3.2 the Responsible Entity experiences:
•
multiple Contingencies where the combined MW loss exceeds its Most
Severe Single Contingency and that are defined as a single Balancing Contingency
Event, or
•
multiple Balancing Contingency Events within the sum of the time periods
defined by the Contingency Event Recovery Period and Contingency Reserve
Restoration Period whose combined magnitude exceeds the Responsible Entity's
Most Severe Single Contingency.
Rationale R1
Requirement R1 reflects the operating principles first established by NERC Policy 1 (Generation
Control and Performance). Its objective is to assure the Responsible Entity balances resources and
demand and returns its Reporting Area Control Error (ACE) to defined values (subject to applicable
limits) following a Reportable Balancing Contingency Event. It requires the Responsible Entity to
recover from events that would be less than or equal to the Responsible Entity’s MSSC. It
establishes the amount of Contingency Reserve and recovery and restoration timeframes the
Responsible Entity must demonstrate in a compliance evaluation. It is intended to eliminate the
ambiguities and questions associated with the existing standard. In addition, it allows Responsible
Entities to have a clear way to demonstrate compliance and support the Interconnection to the full
extent of its MSSC.
Requirement R1 does not apply when an entity experiences a Balancing Contingency Event that
exceeds its MSSC (which includes multiple Balancing Contingency Events as described in R1 part
1.3.2 below) because a fundamental goal of the SDT is to assure the Responsible Entity has enough
flexibility to maintain service to Demand while managing reliability. The SDT’s intent is to
eliminate any potential overlap or conflict with any other NERC Reliability Standard to eliminate
duplicative reporting, and other issues.
Commenters suggested a Quarterly Compliance similar to the current reports sent to NERC. The
drafting team attempted to draft measurement language and VSL’s for quarterly monitoring of
compliance to R1. But the drafting team found that the VSL levels developed were likely to place
smaller Balancing Authority’s (BA) and Reserve Sharing Groups (RSG) in a severe violation
regardless of the size of the failure. Therefore, the drafting team has not adopted a quarterly
compliance calculation. Also, the proposed requirement and compliance process meets the
directive in Paragraph 354 of Order 693.
The language in R1 part 1.3 does not specifically state under which EEA level the exclusion applies
to reduce the need for consequent modifications of the BAL‐002 standard. Thus, language in
Requirement 1 Part 1.3.1 addresses both current and future EEA process. In addition, the drafting
team has added language to R 1.3.1 clarifying that if a BA is experiencing an EEA event under
BAL‐002‐3 Rationales
February 2018
2
which its contingency reserve has been activated, the RSG in which it resides would also be
considered to be exempt from R1 compliance.
In addition, to address FERC Order No. 835, the drafting team has modified Requirement R1 Part
1.3.1 to clarify that the Responsible Entity, is the Balancing Authority (BA) notifying the Reliability
Coordinator (RC) of the conditions set forth in Requirement R1, Part 1.3.1 in accordance with the
Energy Emergency Alert (EEA) procedures. Under the Energy Emergency Alert procedures, the BA
must inform the RC of the conditions and necessary requirements to meet reliability and the RC
must approve of the information being provided before issuing an Energy Emergency Alert.
Requirement R1 Part 1.3.1 requires the BA to provide additional information to the RC, allowing
the RC to have a wide‐area view of the state of the Bulk Electric System for possible future
decisions concerning the System. It also provides for relief to a BA or RSG when reserves are being
utilized under an EEA. These modifications keep the issues associated with Energy Emergencies
within the Emergency Preparedness and Operations Standards, while allowing BAL‐002‐3 to
compliment the process and clarify the narrow set of conditions where the BA and/or RSG is not
subject to compliance to R1..
Requirement R2
Each Responsible Entity shall develop, review and maintain annually, and implement an Operating Process
as part of its Operating Plan to determine its Most Severe Single Contingency and make preparations to
have Contingency Reserve equal to, or greater than the Responsible Entity’s Most Severe Single
Contingency available for maintaining system reliability.
Rationale R2
R2 establishes the need to actively plan in the near term (e.g., day‐ahead) for expected Reportable
Balancing Contingency Events. This requirement is similar to the current standard which requires
an entity to have available a level of contingency reserves equal to or greater than its Most Severe
Single Contingency.
Requirement R3
Each Responsible Entity, following a Reportable Balancing Contingency Event, shall restore its Contingency
Reserve to at least its Most Severe Single Contingency, before the end of the Contingency Reserve
Restoration Period, but any Balancing Contingency Event that occurs before the end of a Contingency
Reserve Restoration Period resets the beginning of the Contingency Event Recovery Period.
Rationale R3
This requirement is similar to the existing requirement that an entity that has experienced an
event shall restore its Contingency Reserves within 105 minutes of the event. Note that if an entity
is experiencing an EEA it may need to depend on potential availability (or make ready for potential
curtailment) of its firm loads to restore Contingency Reserve. This is the reason for the changes to
the definition of Contingency Reserve in the posting.
BAL‐002‐3 Rationales
February 2018
3
Standards Announcement
Reminder
Project 2017-06 Modifications to BAL-002-2
Initial Ballot and Non-binding Poll Open through May 7, 2018
Now Available
The initial ballot and non-binding poll of the associated Violation Risk Factors and Violation Severity
Levels for BAL-002-3 Disturbance Control Standard—Contingency Reserve for Recovery from a
Balancing Contingency Event are open through 8 p.m. Eastern, Monday, May 7, 2018.
Balloting
Members of the ballot pools associated with this project can log in and submit their votes by accessing
the Standards Balloting and Commenting System (SBS) here. If you experience difficulties navigating
the SBS, contact Wendy Muller.
•
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will review all
responses received during the comment period and determine the next steps of the project.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Principal Technical Advisor, Darrel Richardson (via email), or at
(609) 613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2017-06 Modifications to BAL-002-2
Comment Period Open through May 7, 2018
Now Available
A 45-day formal comment period for BAL-002-3 Disturbance Control Standard—Contingency Reserve
for Recovery from a Balancing Contingency Event, is open through 8 p.m. Eastern, Monday, May 7,
2018.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience
difficulty navigating the SBS, contact Wendy Muller. An unofficial Word version of the comment form is
posted on the project page.
•
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Friday, April 20, 2018. Registered Ballot Body
members can join the ballot pools here.
Next Steps
An initial ballot and non-binding poll of the associated Violation Risk Factors and Violation Severity
Levels will be conducted April 27 – May 7, 2018.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Principal Technical Advisor, Darrel Richardson (via email), or at
(609) 613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
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Index - NERC Balloting Tool
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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/133)
Ballot Name: 2017-06 Modifications to BAL-002-2 BAL-002-3 IN 1 ST
Voting Start Date: 4/27/2018 12:01:00 AM
Voting End Date: 5/8/2018 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 189
Total Ballot Pool: 231
Quorum: 81.82
Weighted Segment Value: 69.46
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Negative
Fraction
w/
Comment
Segment:
1
54
1
28
0.8
7
0.2
0
11
8
Segment:
2
6
0.2
2
0.2
0
0
0
1
3
Segment:
3
50
1
19
0.655
10
0.345
0
10
11
Segment:
4
14
0.9
5
0.5
4
0.4
0
2
3
Segment:
5
54
1
25
0.676
12
0.324
0
9
8
Segment:
6
43
1
20
0.69
9
0.31
0
7
7
Segment:
7
1
0
0
0
0
0
0
0
1
Segment:
8
1
0
0
0
0
0
0
1
0
Segment:
9
1
0
0
0
0
0
0
1
0
1
0.1
0
2
1
Segment
Segment: 7
3
0.3
0.4
© 2018
NERC
Ver
4.2.1.0
Machine
Name:
ERODVSBSWB02
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Negative
Votes
w/o
Comment
Abstain
No
Vote
8/14/2018
Index - NERC Balloting Tool
Page 2 of 14
Segment
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Totals:
231
5.5
102
3.821
43
Negative
Fraction
w/
Comment
Negative
Votes
w/o
Comment
Abstain
No
Vote
1.679
0
44
42
BALLOT POOL MEMBERS
Show All
Segment
entries
Organization
Search: Search
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Allete - Minnesota Power,
Inc.
Jamie Monette
None
N/A
1
Ameren - Ameren Services
Eric Scott
Negative
Comments
Submitted
1
APS - Arizona Public
Service Co.
Michelle
Amarantos
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia
Robertson
Adrian Andreoiu
Affirmative
N/A
1
Berkshire Hathaway Energy
- MidAmerican Energy Co.
Terry Harbour
Affirmative
N/A
1
Bonneville Power
Administration
Kammy RogersHolliday
Affirmative
N/A
1
Colorado Springs Utilities
Devin Elverdi
Affirmative
N/A
1
Dairyland Power
Cooperative
Renee Leidel
None
N/A
1
Duke Energy
Laura Lee
Affirmative
N/A
Affirmative
N/A
1
Edison International Steven Mavis
Southern California Edison
Company
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02
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Segment
Organization
Page 3 of 14
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Entergy - Entergy Services,
Inc.
Oliver Burke
Abstain
N/A
1
Exelon
Chris Scanlon
None
N/A
1
Gainesville Regional Utilities
David Owens
Brandon
McCormick
Negative
Comments
Submitted
1
Great Plains Energy Kansas City Power and
Light Co.
James McBee
Douglas Webb
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
None
N/A
1
IDACORP - Idaho Power
Company
Laura Nelson
Affirmative
N/A
1
International Transmission
Company Holdings
Corporation
Michael Moltane
Stephanie
Burns
Negative
Third-Party
Comments
1
JEA
Ted Hobson
Joe McClung
Affirmative
N/A
1
Lakeland Electric
Larry Watt
Negative
Third-Party
Comments
1
Lincoln Electric System
Danny Pudenz
Abstain
N/A
1
Long Island Power Authority
Robert Ganley
Abstain
N/A
1
Los Angeles Department of
Water and Power
faranak sarbaz
Affirmative
N/A
1
Lower Colorado River
Authority
William Sanders
None
N/A
1
Manitoba Hydro
Mike Smith
Abstain
N/A
1
MEAG Power
David Weekley
Abstain
N/A
1
Muscatine Power and Water
Andy Kurriger
None
N/A
1
National Grid USA
Michael Jones
Abstain
N/A
1
New York Power Authority
Salvatore
Spagnolo
Abstain
N/A
1
NextEra Energy - Florida
Power and Light Co.
Mike ONeil
Affirmative
N/A
1
NiSource - Northern Indiana
Public Service Co.
Steve Toosevich
Negative
Third-Party
Comments
Scott Miller
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02
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Segment
Organization
Page 4 of 14
Voter
Designated
Proxy
Ballot
NERC
Memo
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
None
N/A
1
Portland General Electric
Co.
Nathaniel Clague
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
Negative
Comments
Submitted
1
PSEG - Public Service
Electric and Gas Co.
Joseph Smith
Affirmative
N/A
1
Public Utility District No. 1 of
Chelan County
Jeff Kimbell
Abstain
N/A
1
Public Utility District No. 1 of
Snohomish County
Long Duong
Affirmative
N/A
1
Sacramento Municipal Utility
District
Arthur Starkovich
Affirmative
N/A
1
Salt River Project
Steven Cobb
Affirmative
N/A
1
Santee Cooper
Shawn Abrams
Affirmative
N/A
1
SCANA - South Carolina
Electric and Gas Co.
Tom Hanzlik
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
Affirmative
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Abstain
N/A
1
Southern Company Southern Company
Services, Inc.
Katherine Prewitt
Affirmative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City of
Tallahassee, FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley Authority
Howell Scott
Negative
Comments
Submitted
1
Tri-State G and T
Tracy Sliman
Abstain
N/A
Joe Tarantino
Association,
Inc.Name: ERODVSBSWB02
© 2018 - NERC Ver 4.2.1.0
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8/14/2018
Index - NERC Balloting Tool
Segment
Organization
Page 5 of 14
Voter
Designated
Proxy
Ballot
NERC
Memo
1
U.S. Bureau of Reclamation
Richard Jackson
Affirmative
N/A
1
Westar Energy
Kevin Giles
Abstain
N/A
1
Western Area Power
Administration
sean erickson
Affirmative
N/A
1
Xcel Energy, Inc.
Dean Schiro
Affirmative
N/A
2
Electric Reliability Council of
Texas, Inc.
Brandon Gleason
Abstain
N/A
2
Independent Electricity
System Operator
Leonard Kula
None
N/A
2
ISO New England, Inc.
Michael Puscas
Affirmative
N/A
2
Midcontinent ISO, Inc.
Terry BIlke
None
N/A
2
New York Independent
System Operator
Gregory Campoli
None
N/A
2
PJM Interconnection, L.L.C.
Mark Holman
Affirmative
N/A
3
Ameren - Ameren Services
David Jendras
Negative
Comments
Submitted
3
APS - Arizona Public
Service Co.
Vivian Vo
Affirmative
N/A
3
Avista - Avista Corporation
Scott Kinney
Affirmative
N/A
3
BC Hydro and Power
Authority
Hootan Jarollahi
Affirmative
N/A
3
Berkshire Hathaway Energy
- MidAmerican Energy Co.
Annette Johnston
Affirmative
N/A
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
City of Vero Beach
Ginny Beigel
Brandon
McCormick
Negative
Comments
Submitted
3
Cleco Corporation
Michelle Corley
Louis Guidry
Affirmative
N/A
3
CPS Energy
James Grimshaw
None
N/A
3
DTE Energy - Detroit Edison
Company
Karie Barczak
None
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
Joshua Eason
Rich Hydzik
Darnez
Gresham
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02
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Index - NERC Balloting Tool
Segment
Organization
Page 6 of 14
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Edison International Southern California Edison
Company
Romel Aquino
Affirmative
N/A
3
Exelon
John Bee
None
N/A
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
None
N/A
3
Florida Municipal Power
Agency
Joe McKinney
Brandon
McCormick
Negative
Comments
Submitted
3
Gainesville Regional Utilities
Ken Simmons
Brandon
McCormick
Negative
Comments
Submitted
3
Georgia System Operations
Corporation
Scott McGough
Abstain
N/A
3
Great Plains Energy Kansas City Power and
Light Co.
John Carlson
Affirmative
N/A
3
Great River Energy
Brian Glover
None
N/A
3
Lincoln Electric System
Jason Fortik
None
N/A
3
Los Angeles Department of
Water and Power
Henry (Hank)
Williams
None
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Abstain
N/A
3
MEAG Power
Roger Brand
Abstain
N/A
3
Muscatine Power and Water
Seth Shoemaker
Negative
Third-Party
Comments
3
National Grid USA
Brian Shanahan
Abstain
N/A
3
Nebraska Public Power
District
Tony Eddleman
Abstain
N/A
3
New York Power Authority
David Rivera
Abstain
N/A
3
NiSource - Northern Indiana
Public Service Co.
Aimee Harris
Negative
Third-Party
Comments
3
Ocala Utility Services
Randy Hahn
Negative
Third-Party
Comments
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Affirmative
N/A
Douglas Webb
Scott Miller
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02
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8/14/2018
Index - NERC Balloting Tool
Segment
Organization
Page 7 of 14
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Owensboro Municipal
Utilities
Thomas Lyons
Affirmative
N/A
3
Platte River Power Authority
Jeff Landis
Abstain
N/A
3
Portland General Electric
Co.
Angela Gaines
Affirmative
N/A
3
PPL - Louisville Gas and
Electric Co.
Charles Freibert
Negative
Comments
Submitted
3
Public Utility District No. 1 of
Chelan County
Joyce Gundry
Abstain
N/A
3
Puget Sound Energy, Inc.
Lynda Kupfer
None
N/A
3
Rutherford EMC
Tom Haire
None
N/A
3
Sacramento Municipal Utility
District
Nicole Looney
Affirmative
N/A
3
Salt River Project
Robert
Kondziolka
Affirmative
N/A
3
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South Carolina
Electric and Gas Co.
Scott Parker
None
N/A
3
Seattle City Light
Tuan Tran
None
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Abstain
N/A
3
Snohomish County PUD No.
1
Mark Oens
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Affirmative
N/A
3
Tacoma Public Utilities
(Tacoma, WA)
Marc Donaldson
Affirmative
N/A
3
Tennessee Valley Authority
Ian Grant
Negative
Comments
Submitted
3
WEC Energy Group, Inc.
Thomas Breene
Negative
Third-Party
Comments
3
Westar Energy
Bo Jones
Abstain
N/A
3
Xcel Energy, Inc.
Michael Ibold
Affirmative
N/A
Joe Tarantino
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02
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8/14/2018
Index - NERC Balloting Tool
Segment
Organization
Page 8 of 14
Voter
Designated
Proxy
Ballot
NERC
Memo
4
Alliant Energy Corporation
Services, Inc.
Larry Heckert
Negative
Third-Party
Comments
4
American Public Power
Association
Jack Cashin
Abstain
N/A
4
Austin Energy
Esther Weekes
Affirmative
N/A
4
City of Poplar Bluff
Neal Williams
None
N/A
4
Florida Municipal Power
Agency
Carol Chinn
Negative
Comments
Submitted
4
Georgia System Operations
Corporation
Guy Andrews
Abstain
N/A
4
MGE Energy - Madison Gas
and Electric Co.
Joseph
DePoorter
Negative
Third-Party
Comments
4
Public Utility District No. 1 of
Snohomish County
John Martinsen
Affirmative
N/A
4
Public Utility District No. 2 of
Grant County, Washington
Yvonne
McMackin
None
N/A
4
Sacramento Municipal Utility
District
Beth Tincher
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Tacoma Public Utilities
(Tacoma, WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian EvansMongeon
None
N/A
4
WEC Energy Group, Inc.
Anthony
Jankowski
Negative
Third-Party
Comments
5
Ameren - Ameren Missouri
Sam Dwyer
Negative
Comments
Submitted
5
APS - Arizona Public
Service Co.
Kelsi Rigby
Affirmative
N/A
5
Austin Energy
Shirley Mathew
Affirmative
N/A
5
Avista - Avista Corporation
Glen Farmer
Affirmative
N/A
5
BC Hydro and Power
Authority
Helen Hamilton
Harding
Affirmative
N/A
Brandon
McCormick
Joe Tarantino
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02
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8/14/2018
Index - NERC Balloting Tool
Segment
Organization
Page 9 of 14
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Berkshire Hathaway - NV
Energy
Kevin Salsbury
Affirmative
N/A
5
Boise-Kuna Irrigation District
- Lucky Peak Power Plant
Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Scott Winner
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
Third-Party
Comments
5
Choctaw Generation Limited
Partnership, LLLP
Rob Watson
None
N/A
5
City Water, Light and Power
of Springfield, IL
Steve Rose
Affirmative
N/A
5
Dairyland Power
Cooperative
Tommy Drea
None
N/A
5
Dominion - Dominion
Resources, Inc.
Lou Oberski
None
N/A
5
DTE Energy - Detroit Edison
Company
Jeffrey DePriest
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Exelon
Ruth Miller
None
N/A
5
Florida Municipal Power
Agency
Chris Gowder
Brandon
McCormick
Negative
Comments
Submitted
5
Great Plains Energy Kansas City Power and
Light Co.
Harold Wyble
Douglas Webb
Affirmative
N/A
5
Great River Energy
Preston Walsh
Negative
Third-Party
Comments
5
Herb Schrayshuen
Herb
Schrayshuen
Affirmative
N/A
5
JEA
John Babik
Affirmative
N/A
5
Kissimmee Utility Authority
Mike Blough
Negative
Comments
Submitted
5
Lakeland Electric
Jim Howard
Negative
Third-Party
Comments
Brandon
McCormick
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02
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8/14/2018
Index - NERC Balloting Tool
Segment
Organization
Page 10 of 14
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Lincoln Electric System
Kayleigh
Wilkerson
Abstain
N/A
5
Los Angeles Department of
Water and Power
Donald
Sievertson
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Abstain
N/A
5
Massachusetts Municipal
Wholesale Electric Company
David Gordon
Abstain
N/A
5
MEAG Power
Steven Grego
Abstain
N/A
5
Muscatine Power and Water
Neal Nelson
Negative
Third-Party
Comments
5
NaturEner USA, LLC
Eric Smith
Affirmative
N/A
5
NB Power Corporation
Laura McLeod
Affirmative
N/A
5
Nebraska Public Power
District
Don Schmit
Abstain
N/A
5
New York Power Authority
Erick Barrios
Abstain
N/A
5
NiSource - Northern Indiana
Public Service Co.
Dmitriy Bazylyuk
Negative
Third-Party
Comments
5
OGE Energy - Oklahoma
Gas and Electric Co.
John Rhea
None
N/A
5
Omaha Public Power District
Mahmood Safi
None
N/A
5
Orlando Utilities Commission
Richard Kinas
Negative
Comments
Submitted
5
Platte River Power Authority
Tyson Archie
Abstain
N/A
5
Portland General Electric
Co.
Ryan Olson
None
N/A
5
PPL - Louisville Gas and
Electric Co.
JULIE
HOSTRANDER
Negative
Comments
Submitted
5
Public Utility District No. 1 of
Chelan County
Haley Sousa
Abstain
N/A
5
Public Utility District No. 1 of
Snohomish County
Sam Nietfeld
Affirmative
N/A
5
Sacramento Municipal Utility
District
Susan Oto
Affirmative
N/A
Scott Miller
Joe Tarantino
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02
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Segment
Organization
Page 11 of 14
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
Santee Cooper
Tommy Curtis
Affirmative
N/A
5
SCANA - South Carolina
Electric and Gas Co.
Alyssa Hubbard
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Affirmative
N/A
5
Tacoma Public Utilities
(Tacoma, WA)
Ozan Ferrin
Affirmative
N/A
5
Tennessee Valley Authority
M Lee Thomas
Negative
Comments
Submitted
5
Tri-State G and T
Association, Inc.
Mark Stein
None
N/A
5
U.S. Bureau of Reclamation
Wendy Center
Affirmative
N/A
5
WEC Energy Group, Inc.
Linda Horn
Negative
Third-Party
Comments
5
Westar Energy
Laura Cox
Abstain
N/A
5
Xcel Energy, Inc.
Gerry Huitt
Affirmative
N/A
6
Ameren - Ameren Services
Robert Quinlivan
Negative
Comments
Submitted
6
APS - Arizona Public
Service Co.
Jonathan Aragon
Affirmative
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
None
N/A
6
Black Hills Corporation
Eric Scherr
None
N/A
6
Bonneville Power
Administration
Andrew Meyers
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Affirmative
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
None
N/A
6
Edison International Kenya Streeter
Southern California Edison
Company
© 2018 - NERC Ver 4.2.1.0
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Louis Guidry
8/14/2018
Index - NERC Balloting Tool
Segment
Organization
Page 12 of 14
Voter
6
Exelon
Becky Webb
6
Florida Municipal Power
Agency
Richard
Montgomery
6
Florida Municipal Power
Pool
6
Designated
Proxy
Ballot
NERC
Memo
None
N/A
Brandon
McCormick
Negative
Comments
Submitted
Tom Reedy
Brandon
McCormick
Negative
Comments
Submitted
Great Plains Energy Kansas City Power and
Light Co.
Jennifer
Flandermeyer
Douglas Webb
Affirmative
N/A
6
Great River Energy
Donna
Stephenson
Michael
Brytowski
Negative
Third-Party
Comments
6
Lincoln Electric System
Eric Ruskamp
Abstain
N/A
6
Los Angeles Department of
Water and Power
Anton Vu
Affirmative
N/A
6
Luminant - Luminant Energy
Brenda Hampton
None
N/A
6
Manitoba Hydro
Blair Mukanik
Abstain
N/A
6
Muscatine Power and Water
Ryan Streck
Negative
Third-Party
Comments
6
New York Power Authority
Shivaz Chopra
Abstain
N/A
6
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Affirmative
N/A
6
NiSource - Northern Indiana
Public Service Co.
Joe O'Brien
Negative
Third-Party
Comments
6
Northern California Power
Agency
Dennis Sismaet
Abstain
N/A
6
OGE Energy - Oklahoma
Gas and Electric Co.
Sing Tay
Affirmative
N/A
6
Portland General Electric
Co.
Daniel Mason
Affirmative
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Negative
Comments
Submitted
6
PSEG - PSEG Energy
Resources and Trade LLC
Karla Barton
None
N/A
6
Public Utility District No. 1 of
Chelan County
Davis Jelusich
Abstain
N/A
Shelly Dineen
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Segment
Organization
Page 13 of 14
Voter
6
Public Utility District No. 2 of
Grant County, Washington
LeRoy Patterson
6
Sacramento Municipal Utility
District
Jamie Cutlip
6
Salt River Project
6
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Affirmative
N/A
Bobby Olsen
Affirmative
N/A
Santee Cooper
Michael Brown
Affirmative
N/A
6
SCANA - South Carolina
Electric and Gas Co.
John Folsom
None
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Abstain
N/A
6
Snohomish County PUD No.
1
Franklin Lu
Affirmative
N/A
6
Southern Company Southern Company
Generation and Energy
Marketing
Jennifer Sykes
Affirmative
N/A
6
Tacoma Public Utilities
(Tacoma, WA)
Rick Applegate
Affirmative
N/A
6
Tennessee Valley Authority
Marjorie Parsons
Negative
Comments
Submitted
6
WEC Energy Group, Inc.
David Hathaway
Negative
Third-Party
Comments
6
Westar Energy
Megan Wagner
Abstain
N/A
6
Western Area Power
Administration
Charles Faust
Affirmative
N/A
6
Xcel Energy, Inc.
Carrie Dixon
Affirmative
N/A
7
Luminant Mining Company
LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Abstain
N/A
9
Commonwealth of
Massachusetts Department
of Public Utilities
Donald Nelson
Abstain
N/A
10
Midwest Reliability
Russel Mountjoy
Negative
Third-Party
Comments
Organization
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Voter
Designated
Proxy
Ballot
NERC
Memo
10
New York State Reliability
Council
ALAN
ADAMSON
Affirmative
N/A
10
Northeast Power
Coordinating Council
Guy V. Zito
Abstain
N/A
10
ReliabilityFirst
Anthony
Jablonski
Affirmative
N/A
10
SERC Reliability
Corporation
Drew Slabaugh
None
N/A
10
Texas Reliability Entity, Inc.
Rachel Coyne
Abstain
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
Previous
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Showing 1 to 231 of 231 entries
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BALLOT RESULTS
Ballot Name: 2017-06 Modifications to BAL-002-2 BAL-002-3 Non-binding Poll IN 1 NB
Voting Start Date: 4/27/2018 12:01:00 AM
Voting End Date: 5/8/2018 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 176
Total Ballot Pool: 220
Quorum: 80
Weighted Segment Value: 77.19
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
1
50
1
24
0.857
4
0.143
14
8
Segment:
2
6
0.2
2
0.2
0
0
1
3
Segment:
3
50
1
16
0.696
7
0.304
15
12
Segment:
4
14
0.7
5
0.5
2
0.2
3
4
Segment:
5
50
1
22
0.733
8
0.267
12
8
Segment:
6
40
1
15
0.75
5
0.25
13
7
Segment:
7
1
0
0
0
0
0
0
1
Segment:
8
1
0
0
0
0
0
1
0
Segment:
9
1
0
0
0
0
0
1
0
Segment:
10
7
0.4
4
0.4
0
0
2
1
26
1.164
62
44
Segment
Totals:
88
4.136
220
5.3
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BALLOT POOL MEMBERS
Show All
Segment
entries
Organization
Search: Search
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Ameren - Ameren Services
Eric Scott
None
N/A
1
APS - Arizona Public
Service Co.
Michelle
Amarantos
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia
Robertson
Adrian Andreoiu
Abstain
N/A
1
Berkshire Hathaway Energy
- MidAmerican Energy Co.
Terry Harbour
Affirmative
N/A
1
Bonneville Power
Administration
Kammy RogersHolliday
Affirmative
N/A
1
Colorado Springs Utilities
Devin Elverdi
Affirmative
N/A
1
Dairyland Power
Cooperative
Renee Leidel
None
N/A
1
Duke Energy
Laura Lee
Affirmative
N/A
1
Edison International Southern California Edison
Company
Steven Mavis
Affirmative
N/A
1
Entergy - Entergy Services,
Inc.
Oliver Burke
Abstain
N/A
1
Exelon
Chris Scanlon
None
N/A
1
Great Plains Energy Kansas City Power and Light
Co.
James McBee
Affirmative
N/A
1
Great River Energy
Gordon Pietsch
None
N/A
Douglas Webb
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Voter
1
IDACORP - Idaho Power
Company
Laura Nelson
1
International Transmission
Company Holdings
Corporation
Michael Moltane
1
JEA
Ted Hobson
1
Lakeland Electric
1
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Stephanie
Burns
Negative
Comments
Submitted
Joe McClung
Affirmative
N/A
Larry Watt
Negative
Comments
Submitted
Lincoln Electric System
Danny Pudenz
Abstain
N/A
1
Long Island Power Authority
Robert Ganley
Abstain
N/A
1
Los Angeles Department of
Water and Power
faranak sarbaz
Affirmative
N/A
1
Lower Colorado River
Authority
William Sanders
None
N/A
1
Manitoba Hydro
Mike Smith
Abstain
N/A
1
MEAG Power
David Weekley
Abstain
N/A
1
Muscatine Power and Water
Andy Kurriger
None
N/A
1
National Grid USA
Michael Jones
Abstain
N/A
1
New York Power Authority
Salvatore
Spagnolo
Abstain
N/A
1
NextEra Energy - Florida
Power and Light Co.
Mike ONeil
Affirmative
N/A
1
NiSource - Northern Indiana
Public Service Co.
Steve Toosevich
Negative
Comments
Submitted
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy - Oklahoma
Gas and Electric Co.
Terri Pyle
Affirmative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
None
N/A
1
Portland General Electric
Co.
Nathaniel Clague
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
Abstain
N/A
Scott Miller
Dori Quam
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Voter
Designated
Proxy
Ballot
NERC
Memo
1
PSEG - Public Service
Electric and Gas Co.
Joseph Smith
Abstain
N/A
1
Public Utility District No. 1 of
Snohomish County
Long Duong
Affirmative
N/A
1
Sacramento Municipal Utility
District
Arthur Starkovich
Affirmative
N/A
1
Salt River Project
Steven Cobb
Affirmative
N/A
1
Santee Cooper
Shawn Abrams
Abstain
N/A
1
SCANA - South Carolina
Electric and Gas Co.
Tom Hanzlik
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
Affirmative
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Abstain
N/A
1
Southern Company Southern Company
Services, Inc.
Katherine Prewitt
Affirmative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City of
Tallahassee, FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley Authority
Howell Scott
Negative
Comments
Submitted
1
Tri-State G and T
Association, Inc.
Tracy Sliman
Abstain
N/A
1
U.S. Bureau of Reclamation
Richard Jackson
Affirmative
N/A
1
Westar Energy
Kevin Giles
Abstain
N/A
1
Western Area Power
Administration
sean erickson
Affirmative
N/A
2
Electric Reliability Council of
Texas, Inc.
Brandon Gleason
Abstain
N/A
2
Independent Electricity
System Operator
Leonard Kula
None
N/A
2
ISO New England, Inc.
Michael Puscas
Affirmative
N/A
None
N/A
2 - NERC Ver 4.2.1.0
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Inc. ERODVSBSWB02
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Joshua Eason
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Organization
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Voter
Designated
Proxy
Ballot
NERC
Memo
2
New York Independent
System Operator
Gregory Campoli
None
N/A
2
PJM Interconnection, L.L.C.
Mark Holman
Affirmative
N/A
3
Ameren - Ameren Services
David Jendras
Abstain
N/A
3
APS - Arizona Public
Service Co.
Vivian Vo
Affirmative
N/A
3
Avista - Avista Corporation
Scott Kinney
Affirmative
N/A
3
BC Hydro and Power
Authority
Hootan Jarollahi
Abstain
N/A
3
Berkshire Hathaway Energy
- MidAmerican Energy Co.
Annette Johnston
Affirmative
N/A
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
City of Vero Beach
Ginny Beigel
Brandon
McCormick
Negative
Comments
Submitted
3
Cleco Corporation
Michelle Corley
Louis Guidry
Affirmative
N/A
3
CPS Energy
James Grimshaw
None
N/A
3
DTE Energy - Detroit Edison
Company
Karie Barczak
None
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California Edison
Company
Romel Aquino
Affirmative
N/A
3
Exelon
John Bee
None
N/A
3
FirstEnergy - FirstEnergy
Corporation
Aaron
Ghodooshim
None
N/A
3
Florida Municipal Power
Agency
Joe McKinney
Brandon
McCormick
Negative
Comments
Submitted
3
Gainesville Regional Utilities
Ken Simmons
Brandon
McCormick
Negative
Comments
Submitted
3
Georgia System Operations
Corporation
Scott McGough
Abstain
N/A
Rich Hydzik
Darnez
Gresham
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Segment
Organization
Page 6 of 13
Voter
3
Great Plains Energy Kansas City Power and Light
Co.
John Carlson
3
Great River Energy
3
Designated
Proxy
Douglas Webb
Ballot
NERC
Memo
Affirmative
N/A
Brian Glover
None
N/A
Lincoln Electric System
Jason Fortik
None
N/A
3
Los Angeles Department of
Water and Power
Henry (Hank)
Williams
None
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Abstain
N/A
3
MEAG Power
Roger Brand
Abstain
N/A
3
Muscatine Power and Water
Seth Shoemaker
Negative
Comments
Submitted
3
National Grid USA
Brian Shanahan
Abstain
N/A
3
Nebraska Public Power
District
Tony Eddleman
Abstain
N/A
3
New York Power Authority
David Rivera
Abstain
N/A
3
NiSource - Northern Indiana
Public Service Co.
Aimee Harris
Negative
Comments
Submitted
3
Ocala Utility Services
Randy Hahn
Negative
Comments
Submitted
3
OGE Energy - Oklahoma
Gas and Electric Co.
Donald Hargrove
Affirmative
N/A
3
Owensboro Municipal
Utilities
Thomas Lyons
Affirmative
N/A
3
Platte River Power Authority
Jeff Landis
Abstain
N/A
3
Portland General Electric
Co.
Angela Gaines
Affirmative
N/A
3
PPL - Louisville Gas and
Electric Co.
Charles Freibert
None
N/A
3
Public Utility District No. 1 of
Chelan County
Joyce Gundry
Abstain
N/A
3
Puget Sound Energy, Inc.
Lynda Kupfer
None
N/A
3
Rutherford EMC
Tom Haire
None
N/A
Scott Miller
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Voter
3
Sacramento Municipal Utility
District
Nicole Looney
3
Salt River Project
3
Designated
Proxy
Joe Tarantino
Ballot
NERC
Memo
Affirmative
N/A
Robert
Kondziolka
Affirmative
N/A
Santee Cooper
James Poston
Abstain
N/A
3
SCANA - South Carolina
Electric and Gas Co.
Scott Parker
None
N/A
3
Seattle City Light
Tuan Tran
None
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Abstain
N/A
3
Snohomish County PUD No.
1
Mark Oens
Affirmative
N/A
3
Southern Company Alabama Power Company
Joel Dembowski
Affirmative
N/A
3
Tacoma Public Utilities
(Tacoma, WA)
Marc Donaldson
Affirmative
N/A
3
Tennessee Valley Authority
Ian Grant
Abstain
N/A
3
WEC Energy Group, Inc.
Thomas Breene
Negative
Comments
Submitted
3
Westar Energy
Bo Jones
Abstain
N/A
3
Xcel Energy, Inc.
Michael Ibold
Abstain
N/A
4
Alliant Energy Corporation
Services, Inc.
Larry Heckert
None
N/A
4
American Public Power
Association
Jack Cashin
Abstain
N/A
4
Austin Energy
Esther Weekes
Affirmative
N/A
4
City of Poplar Bluff
Neal Williams
None
N/A
4
Florida Municipal Power
Agency
Carol Chinn
Negative
Comments
Submitted
4
Georgia System Operations
Corporation
Guy Andrews
Abstain
N/A
4
MGE Energy - Madison Gas
and Electric Co.
Joseph
DePoorter
Abstain
N/A
Brandon
McCormick
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Organization
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Voter
Designated
Proxy
Ballot
NERC
Memo
4
Public Utility District No. 1 of
Snohomish County
John Martinsen
Affirmative
N/A
4
Public Utility District No. 2 of
Grant County, Washington
Yvonne
McMackin
None
N/A
4
Sacramento Municipal Utility
District
Beth Tincher
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Tacoma Public Utilities
(Tacoma, WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian EvansMongeon
None
N/A
4
WEC Energy Group, Inc.
Anthony
Jankowski
Negative
Comments
Submitted
5
Ameren - Ameren Missouri
Sam Dwyer
Abstain
N/A
5
APS - Arizona Public
Service Co.
Kelsi Rigby
Affirmative
N/A
5
Austin Energy
Shirley Mathew
Affirmative
N/A
5
Avista - Avista Corporation
Glen Farmer
Affirmative
N/A
5
BC Hydro and Power
Authority
Helen Hamilton
Harding
Abstain
N/A
5
Berkshire Hathaway - NV
Energy
Kevin Salsbury
Affirmative
N/A
5
Boise-Kuna Irrigation District
- Lucky Peak Power Plant
Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Scott Winner
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
Comments
Submitted
5
Choctaw Generation Limited
Partnership, LLLP
Rob Watson
None
N/A
5
City Water, Light and Power
of Springfield, IL
Steve Rose
Affirmative
N/A
5
Dairyland Power
Tommy Drea
None
N/A
Joe Tarantino
Cooperative
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Voter
Designated
Proxy
Ballot
NERC
Memo
5
Dominion - Dominion
Resources, Inc.
Lou Oberski
None
N/A
5
DTE Energy - Detroit Edison
Company
Jeffrey DePriest
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Exelon
Ruth Miller
None
N/A
5
Florida Municipal Power
Agency
Chris Gowder
Brandon
McCormick
Negative
Comments
Submitted
5
Great Plains Energy Kansas City Power and Light
Co.
Harold Wyble
Douglas Webb
Affirmative
N/A
5
Great River Energy
Preston Walsh
Negative
Comments
Submitted
5
Herb Schrayshuen
Herb
Schrayshuen
Affirmative
N/A
5
JEA
John Babik
Affirmative
N/A
5
Kissimmee Utility Authority
Mike Blough
Negative
Comments
Submitted
5
Lakeland Electric
Jim Howard
Negative
Comments
Submitted
5
Lincoln Electric System
Kayleigh
Wilkerson
Abstain
N/A
5
Los Angeles Department of
Water and Power
Donald
Sievertson
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Abstain
N/A
5
Massachusetts Municipal
Wholesale Electric Company
David Gordon
Abstain
N/A
5
MEAG Power
Steven Grego
Abstain
N/A
5
Muscatine Power and Water
Neal Nelson
Negative
Comments
Submitted
5
NaturEner USA, LLC
Eric Smith
Affirmative
N/A
5
NB Power Corporation
Laura McLeod
Affirmative
N/A
Abstain
N/A
5
Nebraska Public Power
Don Schmit
District
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Scott Miller
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Organization
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Voter
Designated
Proxy
Ballot
NERC
Memo
5
New York Power Authority
Erick Barrios
Abstain
N/A
5
NiSource - Northern Indiana
Public Service Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
5
OGE Energy - Oklahoma
Gas and Electric Co.
John Rhea
None
N/A
5
Omaha Public Power District
Mahmood Safi
None
N/A
5
Orlando Utilities Commission
Richard Kinas
Negative
Comments
Submitted
5
Portland General Electric
Co.
Ryan Olson
None
N/A
5
PPL - Louisville Gas and
Electric Co.
JULIE
HOSTRANDER
None
N/A
5
Public Utility District No. 1 of
Chelan County
Haley Sousa
Abstain
N/A
5
Public Utility District No. 1 of
Snohomish County
Sam Nietfeld
Affirmative
N/A
5
Sacramento Municipal Utility
District
Susan Oto
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
Santee Cooper
Tommy Curtis
Abstain
N/A
5
SCANA - South Carolina
Electric and Gas Co.
Alyssa Hubbard
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Affirmative
N/A
5
Tacoma Public Utilities
(Tacoma, WA)
Ozan Ferrin
Affirmative
N/A
5
Tennessee Valley Authority
M Lee Thomas
Abstain
N/A
5
U.S. Bureau of Reclamation
Wendy Center
Affirmative
N/A
5
Westar Energy
Laura Cox
Abstain
N/A
6
Ameren - Ameren Services
Robert Quinlivan
Abstain
N/A
6
APS - Arizona Public
Service Co.
Jonathan Aragon
Affirmative
N/A
Joe Tarantino
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Voter
Designated
Proxy
Ballot
NERC
Memo
6
Black Hills Corporation
Eric Scherr
None
N/A
6
Bonneville Power
Administration
Andrew Meyers
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Abstain
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Edison International Southern California Edison
Company
Kenya Streeter
None
N/A
6
Exelon
Becky Webb
None
N/A
6
Florida Municipal Power
Agency
Richard
Montgomery
Brandon
McCormick
Negative
Comments
Submitted
6
Florida Municipal Power
Pool
Tom Reedy
Brandon
McCormick
Negative
Comments
Submitted
6
Great Plains Energy Kansas City Power and Light
Co.
Jennifer
Flandermeyer
Douglas Webb
Affirmative
N/A
6
Great River Energy
Donna
Stephenson
Michael
Brytowski
Negative
Comments
Submitted
6
Lincoln Electric System
Eric Ruskamp
Abstain
N/A
6
Los Angeles Department of
Water and Power
Anton Vu
Affirmative
N/A
6
Luminant - Luminant Energy
Brenda Hampton
None
N/A
6
Manitoba Hydro
Blair Mukanik
Abstain
N/A
6
Muscatine Power and Water
Ryan Streck
Negative
Comments
Submitted
6
New York Power Authority
Shivaz Chopra
Abstain
N/A
6
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Abstain
N/A
6
NiSource - Northern Indiana
Public Service Co.
Joe O'Brien
Negative
Comments
Submitted
Abstain
N/A
6
Northern California Power
Dennis Sismaet
Agency
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Voter
Designated
Proxy
Ballot
NERC
Memo
6
OGE Energy - Oklahoma
Gas and Electric Co.
Sing Tay
Affirmative
N/A
6
Portland General Electric
Co.
Daniel Mason
Affirmative
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
None
N/A
6
PSEG - PSEG Energy
Resources and Trade LLC
Karla Barton
None
N/A
6
Public Utility District No. 1 of
Chelan County
Davis Jelusich
Abstain
N/A
6
Public Utility District No. 2 of
Grant County, Washington
LeRoy Patterson
Abstain
N/A
6
Sacramento Municipal Utility
District
Jamie Cutlip
Affirmative
N/A
6
Salt River Project
Bobby Olsen
Affirmative
N/A
6
Santee Cooper
Michael Brown
Abstain
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Abstain
N/A
6
Snohomish County PUD No.
1
Franklin Lu
Affirmative
N/A
6
Southern Company Southern Company
Generation and Energy
Marketing
Jennifer Sykes
Affirmative
N/A
6
Tacoma Public Utilities
(Tacoma, WA)
Rick Applegate
Affirmative
N/A
6
Tennessee Valley Authority
Marjorie Parsons
Abstain
N/A
6
Westar Energy
Megan Wagner
Abstain
N/A
6
Western Area Power
Administration
Charles Faust
Affirmative
N/A
6
Xcel Energy, Inc.
Carrie Dixon
None
N/A
7
Luminant Mining Company
LLC
Stewart Rake
None
N/A
Joe Tarantino
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02
https://sbs.nerc.net/BallotResults/Index/244
8/14/2018
Index - NERC Balloting Tool
Segment
Organization
Page 13 of 13
Voter
Designated
Proxy
Ballot
NERC
Memo
8
David Kiguel
David Kiguel
Abstain
N/A
9
Commonwealth of
Massachusetts Department
of Public Utilities
Donald Nelson
Abstain
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Affirmative
N/A
10
New York State Reliability
Council
ALAN
ADAMSON
Affirmative
N/A
10
Northeast Power
Coordinating Council
Guy V. Zito
Abstain
N/A
10
ReliabilityFirst
Anthony
Jablonski
Affirmative
N/A
10
SERC Reliability Corporation
Drew Slabaugh
None
N/A
10
Texas Reliability Entity, Inc.
Rachel Coyne
Abstain
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
Previous
1
Next
Showing 1 to 220 of 220 entries
© 2018 - NERC Ver 4.2.1.0 Machine Name: ERODVSBSWB02
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8/14/2018
Standards Announcement
Project 2017-06 Modifications to BAL-002-2
Comment Period Open through May 7, 2018
Now Available
A 45-day formal comment period for BAL-002-3 Disturbance Control Standard—Contingency Reserve
for Recovery from a Balancing Contingency Event, is open through 8 p.m. Eastern, Monday, May 7,
2018.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience
difficulty navigating the SBS, contact Wendy Muller. An unofficial Word version of the comment form is
posted on the project page.
•
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Friday, April 20, 2018. Registered Ballot Body
members can join the ballot pools here.
Next Steps
An initial ballot and non-binding poll of the associated Violation Risk Factors and Violation Severity
Levels will be conducted April 27 – May 7, 2018.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Principal Technical Advisor, Darrel Richardson (via email), or at
(609) 613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Comment Report
Project Name:
2017-06 Modifications to BAL-002-2 | BAL-002-3
Comment Period Start Date:
3/22/2018
Comment Period End Date:
5/8/2018
Associated Ballots:
2017-06 Modifications to BAL-002-2 BAL-002-3 IN 1 ST
There were 30 sets of responses, including comments from approximately 115 different people from approximately 87 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
Questions
1. The SDT has modified Requirement R1 to address the Commission’s concerns identified in FERC Order 835. Do you agree that the
proposed modifications clearly state the intentions of the SAR? If not, please state your concerns and provide specific language on the
proposed revision.
2. Do you have any other comments for drafting team consideration?
Organization
Name
Brandon
McCormick
ACES Power
Marketing
Name
Segment(s)
Brandon
McCormick
Brian Van
Gheem
Region
FRCC
6
NA - Not
Applicable
Group Name
FMPA
Group Member
Name
Group
Member
Organization
Group
Member
Segment(s)
Group Member
Region
Tim Beyrle
City of New
4
Smyrna Beach
Utilities
Commission
FRCC
Jim Howard
Lakeland
Electric
5
FRCC
Lynne Mila
City of
Clewiston
4
FRCC
Javier Cisneros
Fort Pierce
Utilities
Authority
3
FRCC
Randy Hahn
Ocala Utility
Services
3
FRCC
Don Cuevas
Beaches
Energy
Services
1
FRCC
Jeffrey Partington Keys Energy
Services
4
FRCC
Tom Reedy
6
FRCC
Steven Lancaster Beaches
Energy
Services
3
FRCC
Mike Blough
Kissimmee
Utility
Authority
5
FRCC
Chris Adkins
City of
Leesburg
3
FRCC
Ginny Beigel
City of Vero
Beach
3
FRCC
Rayburn
Country
Electric
Cooperative,
Inc.
3
SPP RE
Hoosier
Energy Rural
Electric
Cooperative,
Inc.
1
RF
ACES
Greg Froehling
Standards
Collaborators
Bob Solomon
Florida
Municipal
Power Pool
Duke Energy
MRO
Colby Bellville 1,3,5,6
Cynthia Kneisl 1,2,3,4,5,6
FRCC,RF,SERC Duke Energy
MRO
MRO NSRF
Ginger Mercier
Prairie Power, 1,3
Inc.
SERC
John Shaver
Arizona
1
Electric Power
Cooperative,
Inc.
WECC
Michael
Brytowski
Great River
Energy
1,3,5,6
MRO
Bill Hutchison
Southern
Illinois Power
Cooperative
1
SERC
Doug Hils
Duke Energy
1
RF
Lee Schuster
Duke Energy
3
FRCC
Dale Goodwine
Duke Energy
5
SERC
Greg Cecil
Duke Energy
6
RF
Joseph
DePoorter
Madison Gas
& Electric
3,4,5,6
MRO
Larry Heckert
Alliant Energy 4
MRO
Amy Casucelli
Xcel Energy
1,3,5,6
MRO
Michael
Brytowski
Great River
Energy
1,3,5,6
MRO
Jodi Jensen
Western Area 1,6
Power
Administration
MRO
Kayleigh
Wilkerson
Lincoln
Electric
System
5
MRO
Kayleigh
Wilkerson
Lincoln
Electric
System
1,3,5,6
MRO
Mahmood Safi
Omaha Public 1,3,5,6
Power District
MRO
Brad Parret
Minnesota
Power
1,5
MRO
Terry Harbour
MidAmerican
Energy
Corporation
1,3
MRO
Tom Breene
Wisconsin
3,4,5
Public Service
MRO
Jeremy Voll
Basin Electric 1
Power
Cooperative
MRO
Tennessee
Valley
Authority
Dennis
Chastain
Southern
Katherine
Company Prewitt
Southern
Company
Services, Inc.
Tennessee
Valley
Authority
1,3,5,6
1
M Lee Thomas 5
SERC
Tennessee
Valley
Authority
Southern
Company
Tennessee
Valley
Authority
Kevin Lyons
Central Iowa
Power
Cooperative
1
MRO
MIke Morrow
Midcontinent
Independent
System
Operator
2
MRO
Andy Fuhrman
Minnkota
Power
Cooperative
1
MRO
DeWayne Scott
Tennessee
Valley
Authority
1
SERC
Ian Grant
Tennessee
Valley
Authority
3
SERC
Brandy Spraker
Tennessee
Valley
Authority
5
SERC
Marjorie Parsons Tennessee
Valley
Authority
6
SERC
Scott Moore
Alabama
Power
Company
3
SERC
Bill Shultz
Southern
Company
Generation
5
SERC
Jennifer Sykes
Southern
Company
Generation
and Energy
Marketing
6
SERC
Howell Scott
Tennessee
Valley
Authority
1
SERC
Ian Grant
Tennessee
Valley
Authority
3
SERC
M Lee Thomas
Tennessee
Valley
Authority
5
SERC
Marjorie Parsons Tennessee
Valley
Authority
6
SERC
Northeast
Power
Coordinating
Council
Ruida Shu
1,2,3,4,5,6,7,8,9,10 NPCC
RSC no
Guy V. Zito
Dominion and
NYISO
Northeast
Power
Coordinating
Council
10
NPCC
Randy
MacDonald
New
Brunswick
Power
2
NPCC
Wayne Sipperly
New York
Power
Authority
4
NPCC
Glen Smith
Entergy
Services
4
NPCC
Brian Robinson
Utility Services 5
NPCC
Alan Adamson
New York
State
Reliability
Council
7
NPCC
Edward Bedder
Orange &
Rockland
Utilities
1
NPCC
David Burke
Orange &
Rockland
Utilities
3
NPCC
Michele Tondalo UI
1
NPCC
Laura Mcleod
NB Power
1
NPCC
David
Ramkalawan
Ontario Power 5
Generation
Inc.
NPCC
Helen Lainis
IESO
2
NPCC
Michael
Schiavone
National Grid
1
NPCC
Michael Jones
National Grid
3
NPCC
Michael Forte
Con Ed Consolidated
Edison
1
NPCC
Peter Yost
Con Ed 3
Consolidated
Edison Co. of
New York
NPCC
Sean Cavote
PSEG
4
NPCC
Kathleen
Goodman
ISO-NE
2
NPCC
Dominion Dominion
Resources,
Inc.
Southwest
Power Pool,
Inc. (RTO)
Sean Bodkin
Shannon
Mickens
6
2
Dominion
SPP RE
Paul Malozewski Hydro One
3
Networks, Inc.
NPCC
Quintin Lee
Eversource
Energy
NPCC
Dermot Smyth
Con Ed 1,5
Consolidated
Edison Co. of
New York
NPCC
Dermot Smyth
Con Ed 1,5
Consolidated
Edison Co. of
New York
NPCC
Salvatore
Spagnolo
New York
Power
Authority
1
NPCC
Shivaz Chopra
New York
Power
Authority
6
NPCC
David Kiguel
Independent
NA - Not
Applicable
NPCC
Silvia Mitchell
NextEra
6
Energy Florida Power
and Light Co.
NPCC
Caroline Dupuis
Hydro Quebec 1
NPCC
Chantal Mazza
Hydro Quebec 2
NPCC
Connie Lowe
Dominion Dominion
Resources,
Inc.
3
NA - Not
Applicable
Lou Oberski
Dominion Dominion
Resources,
Inc.
5
NA - Not
Applicable
Larry Nash
Dominion 1
Dominion
Virginia Power
NA - Not
Applicable
Southwest
Power Pool
Inc.
2
SPP RE
Don Schmit
Nebraska
Public Power
District
5
SPP RE
Robert Hirchak
Cleco
Corporation
6
SPP RE
SPP
Shannon
Standards
Mickens
Review Group
1
PPL Shelby Wade
Louisville Gas
and Electric
Co.
1,3,5,6
RF,SERC
PPL NERC
Registered
Affiliates
Charlie Freibert
LG&E and KU 3
Energy, LLC
SERC
Brenda Truhe
PPL Electric
Utilities
Corporation
RF
Dan Wilson
LG&E and KU 5
Energy, LLC
SERC
Linn Oelker
LG&E and KU 6
Energy, LLC
SERC
1
1. The SDT has modified Requirement R1 to address the Commission’s concerns identified in FERC Order 835. Do you agree that the
proposed modifications clearly state the intentions of the SAR? If not, please state your concerns and provide specific language on the
proposed revision.
Cynthia Kneisl - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer
No
Document Name
Comment
While the SAR and the proposed changes address the stated FERC directive from one perspective, NERC is authorized to propose an equally effective
alternative to achieve the reliability objective. We believe the approach in the draft standard could negatively impact reliability.
Our comments below outline issues with the standard and the direction it is taking. The change will distract operators from their primary tasks in order
to develop and discuss a plan following a contingency during an Energy Emergency Alert (EEA).
The provisions being changed deal with exclusions to compliance. We believe the better path is for the drafting team to work with NERC (with input
from the NERC OC) to create Implementation Guidance and a companion CMEP Practice Guide that outlines approaches for multi-contingent events,
events > Most Severe Single Contingencies, and for ERO Compliance Staff to handle Reportable Balancing Contingency Events (RBCEs) during
EEAs.
We also believe there is more to gain from a reliability perspective to pass these rare events through the Events Analysis process to create lessonslearned.
Finally, if the drafting team rejects our comments, we believe the change should be limited to: “Notified the RC that they have experienced a Reportable
Balancing Contingency Event (RBCE) in cases where the BA expects recovery to take > 30 minutes and provided proposed actions and an expected
recovery time.”
Likes
0
Dislikes
0
Response
Leonard Kula - Independent Electricity System Operator - 2
Answer
No
Document Name
Comment
While the proposed changes appear to clearly state the intention of the SAR, certain parts appear to be redundant with some of the existing
requirements while other parts seem unnecessary if an alternative means, such as an exception to compliance, is developed.
Firstly, Point (i) in the forth bullet under Part 1.3.1 is unnecessary:
1. The first bullet under Part 1.3.1 implies that a BA’s RC is already aware of the EEA declaration (since it makes that declaration itself!)
2. The RC is already notified of its BA’s emergency condition via EOP-011, Requirement R2 (Part 2.2.1).
Secondly, regarding Point (ii) in Part 1.3.1, a BA’s priority under either an EEA or a capacity or energy emergency is to mitigate the
emergency condition to return the BA Area to normal state. Developing and notifying its RC a plan to recover ACE under either condition
should not be a priority as such a task may actually jeopardize reliability. A BA should be allowed time to manage its EEA and/or emergency.
Only when such issues are duly addressed and the BA is out of EEA and/or emergency should it be required to notify its RC of an ACE
recovery plan, including target recovery time, or the actions being undertaken to recover ACE.
We therefore urge the SDT to seek an alternative means (such as an exception to compliance) to meet the FERC directive on providing an
ACE recovery plan, or to create a Part 1.4 that will require a BA to notify its RC of an ACE recovery plan, including target recovery time or its
actions being undertaken to recover ACE, after it has recovered from an EEA or a capacity or energy emergency.
Likes
0
Dislikes
0
Response
Brandon McCormick - Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 6, 4, 3, 5; Chris Gowder, Florida
Municipal Power Agency, 6, 4, 3, 5; David Owens, Gainesville Regional Utilities, 3, 1, 5; Ginny Beigel, City of Vero Beach, 3; Joe McKinney,
Florida Municipal Power Agency, 6, 4, 3, 5; Ken Simmons, Gainesville Regional Utilities, 3, 1, 5; Mike Blough, Kissimmee Utility Authority, 5,
3; Richard Montgomery, Florida Municipal Power Agency, 6, 4, 3, 5; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick,
Group Name FMPA
Answer
No
Document Name
Comment
: FMPA is concerned that the proposed modifications could potentially be a distraction for operators and negatively impact reliability. We agree with the
following comments submitted by MRO:
While the SAR and the proposed changes address the stated FERC directive from one perspective, NERC is authorized to propose an equally effective
alternative to achieve the reliability objective. We believe the approach in the draft standard could negatively impact reliability.
Our comments below outline issues with the standard and the direction it is taking. The change will distract operators from their primary tasks in order
to develop and discuss a plan following a contingency during an Energy Emergency Alert (EEA).
The provisions being changed deal with exclusions to compliance. We believe the better path is for the drafting team to work with NERC (with input
from the NERC OC) to create Implementation Guidance and a companion CMEP Practice Guide that outlines approaches for multi-contingent events,
events > Most Severe Single Contingencies, and for ERO Compliance Staff to handle Reportable Balancing Contingency Events (RBCEs) during
EEAs.
We also believe there is more to gain from a reliability perspective to pass these rare events through the Events Analysis process to create lessonslearned.
Finally, if the drafting team rejects our comments, we believe the change should be limited to: “Notified the RC that they have experienced a Reportable
Balancing Contingency Event (RBCE) in cases where the BA expects recovery to take > 30 minutes and provided proposed actions and an expected
recovery time.”
Likes
0
Dislikes
0
Response
Richard Kinas - Orlando Utilities Commission - 5
Answer
No
Document Name
Comment
OUC is concerned that the proposed modifications could potentially be a distraction for operators and negatively impact reliability. We agree with the
following comments submitted by MRO:
While the SAR and the proposed changes address the stated FERC directive from one perspective, NERC is authorized to propose an equally effective
alternative to achieve the reliability objective. We believe the approach in the draft standard could negatively impact reliability.
Our comments below outline issues with the standard and the direction it is taking. The change will distract operators from their primary tasks in order
to develop and discuss a plan following a contingency during an Energy Emergency Alert (EEA).
The provisions being changed deal with exclusions to compliance. We believe the better path is for the drafting team to work with NERC (with input
from the NERC OC) to create Implementation Guidance and a companion CMEP Practice Guide that outlines approaches for multi-contingent events,
events > Most Severe Single Contingencies, and for ERO Compliance Staff to handle Reportable Balancing Contingency Events (RBCEs) during
EEAs.
We also believe there is more to gain from a reliability perspective to pass these rare events through the Events Analysis process to create lessonslearned.
Finally, if the drafting team rejects our comments, we believe the change should be limited to: “Notified the RC that they have experienced a Reportable
Balancing Contingency Event (RBCE) in cases where the BA expects recovery to take > 30 minutes and provided proposed actions and an expected
recovery time.”
Likes
0
Dislikes
0
Response
Richard Vine - California ISO - 2
Answer
No
Document Name
Comment
While the SAR and the proposed changes address the stated FERC directive from one perspective, NERC is authorized to propose an equally effective
alternative. We believe the approach in the draft standard could negatively impact reliability.
Our comments below outline issues with the standard and the direction it is taking. The change will distract operators from their primary tasks in order
to develop and discuss a plan following a contingency during an EEA.
The provisions being changed deal with exclusions to compliance. We believe the better path is for the drafting team to work with NERC (with input
from the NERC OC) to create a CMEP Practice Guide that outlines an approach for ERO Compliance Staff to handle RBCEs during these situations.
We also believe there is more to gain from a reliability perspective to pass these rare events through the Events Analysis process to create lessonslearned.
Finally, if the drafting team rejects our comments, we believe the change should be limited to: “Notified the RC that they have experienced a Reportable
Balancing Contingency Event (RBCE) and provided an expected recovery time”.
Likes
0
Dislikes
0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer
No
Document Name
Comment
We believe that the conditions set forth in the first requirement of the FERC order are already accomplished through the requirements in EOP-011 for
declaring an EEA 3 and should not be restated here in BAL-002. A BA experiencing the conditions set forth in the first three bullets in R1.3.1 is by
definition experiencing EEA 3 conditions and the required communication to the RC is satisfied through the request to declare an EEA 3. Restating
them in this standard could lead to conflicts between the standards as they evolve over time. We are also concerned that the current language in the
draft could cause a delay in recovery from an event as the contingent BA’s time is occupied creating a detailed level of audit evidence documenting the
official recovery plan and recovery time estimate during the Recovery Period of the event and then communicating those to the RC. This would only
serve to prolong the threat to the BES caused by the supply shortage which occurred as a result of the contingency.
Likes
0
Dislikes
0
Response
David Jendras - Ameren - Ameren Services - 3
Answer
Document Name
No
Comment
Ameren believes that any Requirement for actions an entity is required to take when experiencing an RC declared EEA level belongs in EOP011, Emergency Operations.
In lieu thereof, Ameren believes the following BAL-002-3 language would be an acceptable alternative to meet the intent and spirit of the
FERC directive, until a revision of EOP-011-1 occurs as described below:
In addition to the redline changes for R1.3 and R1.3.1, Ameren suggests adding the additional bullets as stated below:
•provide updates to the ACE recovery plan, including target recovery time, to its Reliability Coordinator, during its communications with
the RC as required in "Attachment 1-EOP-011-1 Energy Emergency Alerts"
•and implements the ACE recovery plan when given an Operating Instruction to do so by its RC.
Likes
0
Dislikes
0
Response
M Lee Thomas - Tennessee Valley Authority - 5, Group Name Tennessee Valley Authority
Answer
No
Document Name
Comment
TVA believes that the conditions set forth in the 1st requirement of the FERC order are already accomplished through the requirements in EOP-011 for
declaring an EEA 3 and should not be restated here in BAL-002. A BA experiencing the conditions set forth in the first three bullets in R1.3.1 is by
definition experiencing EEA 3 conditions and the required communication to the RC is satisfied through the request to declare an EEA 3. Restating
them in this standard could lead to conflicts between the standards as they evolve over time. We are also concerned that the current language in the
draft could cause a delay in recovery from an event as the contingent BA’s time is occupied creating a detailed level of audit evidence documenting the
official recovery plan and recovery time estimate during the Recovery Period of the event and then communicating those to the RC. This would only
serve to prolong the threat to the BES caused by the supply shortage which occurred as a result of the contingency.
Likes
0
Dislikes
Response
0
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and NYISO
Answer
No
Document Name
Comment
While the proposed changes appear to clearly state the intention of the SAR, certain parts appear to be redundant with some of the existing
requirements while other parts seem unnecessary if an alternative means, such as an exception to compliance, is developed.
Firstly, Point (i) in the forth bullet under Part 1.3.1 is unnecessary:
1. The first bullet under Part 1.3.1 implies that a BA’s RC is already aware of the EEA declaration (since it makes that declaration itself!)
2. The RC is already notified of its BA’s emergency condition via EOP-011, Requirement R2 (Part 2.2.1).
Secondly, regarding Point (ii) in Part 1.3.1, a BA’s priority under either an EEA or a capacity or energy emergency is to mitigate the emergency
condition to return the BA Area to normal state. Developing and notifying its RC a plan to recover ACE under either condition should not be a priority as
such a task may actually jeopardize reliability. A BA should be allowed time to manage its EEA and/or emergency. Only when such issues are duly
addressed and the BA is out of EEA and/or emergency should it be required to notify its RC of an ACE recovery plan, including target recovery time, or
the actions being undertaken to recover ACE.
We therefore urge the SDT to seek an alternative means (such as an exception to compliance) to meet the FERC directive on providing an ACE
recovery plan, or to create a Part 1.4 that will require a BA to notify its RC of an ACE recovery plan, including target recovery time or its actions being
undertaken to recover ACE, after it has recovered from an EEA or a capacity or energy emergency.
Likes
0
Dislikes
0
Response
Brian Van Gheem - ACES Power Marketing - 6, Group Name ACES Standards Collaborators
Answer
No
Document Name
Comment
1. We believe the proposed reference to “preceding two bullet points” should be clarified, as compliance with this requirement can be
confusing. Very few NERC Reliability Requirements identify an action and then follow that with an exemption to the action based on a specific
condition. The proposed changes are made to the exemption portion of the requirement, which already implies that compliance with
Requirement R1 part 1.1 is unnecessary. The embedded dual condition within the proposed bullet should be split to provide clarity. One bullet
should identify the inhibitive reasoning provided to the RC from the distressed BA or RSG that is unable to restore its ACE to the appropriate
Pre
‐R
The
eporting
second
Contingency
bullet should
E vent
alsoACE
identify
Value
thatwithin
the th
ACE recovery plan was provided to the RC.
2. The reference to “recovery time” should be replaced with the appropriate NERC Glossary Term, Contingency Event Recovery Period.
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
N/A to BHC
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
BPA suggests rewording of “an ACE recovery plan” to “actions it will take to recover its ACE”. BPA believes this rewording will help R1 sound less like
a defined term which will depend on or require additional documentation. BPA’s concern is that “an ACE recovery plan” will be assumed to be an
additional document such as the Emergency Operating Plan.
Likes
0
Dislikes
0
Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name
Comment
Yes
SRP supports the proposed revisions.
Likes
0
Dislikes
0
Response
Yvonne McMackin - Public Utility District No. 2 of Grant County, Washington - 4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Glen Farmer - Avista - Avista Corporation - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Michelle Amarantos - APS - Arizona Public Service Co. - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Ozan Ferrin - Tacoma Public Utilities (Tacoma, WA) - 5
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Shelby Wade - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF, Group Name PPL NERC Registered Affiliates
Answer
Document Name
Comment
Yes
Likes
0
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0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Wendy Center - U.S. Bureau of Reclamation - 5
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Selene Willis - Edison International - Southern California Edison Company - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
Yes
Likes
0
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0
Response
Katherine Prewitt - Southern Company - Southern Company Services, Inc. - 1, Group Name Southern Company
Answer
Yes
Document Name
Comment
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0
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0
Response
Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5 - FRCC
Answer
Document Name
Comment
N/a
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0
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0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
The SDT may wish to clarify when the ACE recovery plan must be submitted for a BA to qualify for the exemption. The proposed BAL-002-3 R 1.3 now
specifies that a BA may be exempt from BAL-002-3 R1.1 if it has “during communications with its Reliability Coordinator in accordance with the Energy
Emergency Alert procedure” notified the RC of conditions preventing it from responding and “provided the Reliability Coordinator with an ACE recovery
plan, including target recovery time.”
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0
2. Do you have any other comments for drafting team consideration?
Brian Van Gheem - ACES Power Marketing - 6, Group Name ACES Standards Collaborators
Answer
No
Document Name
Comment
We thank you for this opportunity to comment.
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0
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0
Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
No additional comments.
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0
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0
Response
Katherine Prewitt - Southern Company - Southern Company Services, Inc. - 1, Group Name Southern Company
Answer
No
Document Name
Comment
Likes
0
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0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and NYISO
Answer
No
Document Name
Comment
Likes
0
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0
Response
Selene Willis - Edison International - Southern California Edison Company - 1,3,5,6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
David Jendras - Ameren - Ameren Services - 3
Answer
No
Document Name
Comment
Likes
0
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0
Response
Wendy Center - U.S. Bureau of Reclamation - 5
Answer
No
Document Name
Comment
Likes
0
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0
Response
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Ozan Ferrin - Tacoma Public Utilities (Tacoma, WA) - 5
Answer
No
Document Name
Comment
Likes
0
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0
Response
Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1
Answer
No
Document Name
Comment
Likes
0
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0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
Likes
0
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0
Response
Glen Farmer - Avista - Avista Corporation - 5
Answer
No
Document Name
Comment
Likes
Dislikes
0
0
Response
Kristine Ward - Seminole Electric Cooperative, Inc. - 1,3,4,5 - FRCC
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Yvonne McMackin - Public Utility District No. 2 of Grant County, Washington - 4
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
Likes
0
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0
Response
M Lee Thomas - Tennessee Valley Authority - 5, Group Name Tennessee Valley Authority
Answer
Document Name
Yes
Comment
TVA believes that given the amount of actions BA’s are required to make during a Reportable Disturbance, and the very short window of time allowed in
the standard to successfully complete those actions, that the Standards should not put additional regulatory burden on the operators to create
documentation and notifications during this window. This small amount of time should be dedicated to restoring the BES to a stable condition. It is also
important to note that the contingent BA is still subject to the BAAL limit during a contingency any time the BES is threatened with a negative supply
balance; therefore, the BA still has a compliance obligation to restore its balance anytime the interconnection is threatened even if the BA is not subject
to compliance under BAL-002. Given the small amount of Contingency Reserves available to the BA in this situation and the degree of time urgency,
the BA should make every effort to recover its imbalance and deploy all remaining Contingency Reserves in order to recover as much imbalance as
possible. Only once those actions are completed should the BA focus on communicating the recovery plan and target recovery time to the RC, and this
should not be required to be within the Recovery Period in order to be granted a waiver from compliance under BAL-002.
The proposed revision should be based on BAL-002-2(i), which is the last approved and currently effective version.
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0
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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
The SPP Standards Review Group suggests that the drafting team provide clarity on the intent of the proposed language pertaining to Requirement R1
Part 1.3.1. The proposed language in BAL-002 (Part 1.3.1) is addressing entities that would be in an EEA 3 knowing that they wouldn’t return to an
acceptable status in the required 15 minutes. Looking at EOP-011, any entity that is in an EEA 3 per Attachment 1, that entity would have to report their
status to the Reliability Coordinator (RC) every hour. To our understanding, the entity being identified in BAL-002 (Part 1.3.1-which would be in an EEA
3 situation and would not be in compliance) could make their report in that same hour until they return to an acceptable status. We ask the drafting team
to clarify whether there is connection between the required actions of these two standards. If the drafting team agrees with our understanding, we would
suggest that the drafting team include some language discussing the connection of both standards in BAL-002-3. This would provide clarity on the
expectations of entities that don’t recover in the required 15 minutes as well as being in an EEA 3 condition.
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Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC, Group Name Tennessee Valley Authority
Answer
Document Name
Comment
Yes
We believe that given the amount of actions BA’s are required to make during a Reportable Disturbance, and the very short window of time allowed in
the standard to successfully complete those actions, that the Standards should not put additional regulatory burden on the operators to create
documentation and notifications during this window. This small amount of time should be dedicated to restoring the BES to a stable condition. It is also
important to note that the contingent BA is still subject to the BAAL limit during a contingency any time the BES is threatened with a negative supply
balance; therefore, the BA still has a compliance obligation to restore its balance anytime the interconnection is threatened even if the BA is not subject
to compliance under BAL-002. Given the small amount of Contingency Reserves available to the BA in this situation and the degree of time urgency,
the BA should make every effort to recover its imbalance and deploy all remaining Contingency Reserves in order to recover as much imbalance as
possible. Only once those actions are completed should the BA focus on communicating the recovery plan and target recovery time to the RC, and this
should not be required to be within the Recovery Period in order to be granted a waiver from compliance under BAL-002.
The proposed revision should be based on BAL-002-2(i), which is the last approved and currently effective version.
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0
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0
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Sean Bodkin - Dominion - Dominion Resources, Inc. - 6, Group Name Dominion
Answer
Yes
Document Name
Comment
Dominion Energy has a concern regarding the Technical Rationale document. It appears that SDT has transitioned the existing GTB document to a
Technical Rationale document without completely addressing all of the compliance langugae contained in the document.
"Requirement R1 does not apply when an entity experiences a Balancing Contingency Event that exceeds its MSSC (which includes multiple Balancing
Contingency Events as described in R1 part 1.3.2 below) because a fundamental goal of the SDT is to assure the Responsible Entity has enough
flexibility to maintain service to Demand while managing reliability."
This first example states when an entity does not have to comply and the standard is not applicable. It is not intent, it is a statement that directly impacts
compliance. While the latter section of the section does state what the intent of the SDT was when developing the language and, in isolation would be
appropriate for the TR document, the former part of the statement is not appropriate for the TR document. Just because a statement is not a specific
example of how to comply does not render it appropriate for the TR document.
"In addition, the drafting team has added language to R 1.3.1 clarifying that if a BA is experiencing an EEA event underwhich its contingency reserve
has been activated, the RSG in which it resides would also be considered to be exempt from R1 compliance."
The second quotation also makes a specific compliance statement, exempting a specific entity from compliance of the Requirement. While not an
‘example’ that could be directly ported to an IG document, it is compliance language that is not appropriate for a TR document. As stated before, just
because compliance language does not fit the definition of IG does not render it appropriate for TR.
"Under the Energy Emergency Alert procedures, the BA must inform the RC of the conditions and necessary requirements to meet reliability and the RC
must approve of the information being provided before issuing an Energy Emergency Alert."
The third quotation is a statement that clearly states how to comply with the EEA process. Once again, while not specific IG that statement is not
appropriate for a TR document.
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Richard Vine - California ISO - 2
Answer
Yes
Document Name
Comment
We have concerns related to the unintended reliability consequences associated with the proposed changes in BAL-002-3 regarding the development
and discussion of plans with the Reliability Coordinator in real time to restore ACE following a contingency during capacity shortages.
One thing that seems to be overlooked is that both the BA and RC have obligations in other standards to take action if a BA’s ACE is negatively
impacting frequency or transmission limits.
The exclusion provisions in the current BAL-002-2 deal with situations where the BA has multiple problems (capacity emergency, previous
contingencies or multiple contingencies). Under these situations the BA may likely need to perform dozens of tasks in a 15 minute period.
The role of the Reliability Coordinator is not to manage or approve the local actions taken by the Balancing Authority. The proposed changes would put
two sets of hands on the wheel and delay action. This is the equivalent of asking the pilot upon the loss of an engine to map out actions and reach out
to the air traffic controller to discuss the pilot’s proposal.
The original Disturbance Control Standard (DCS) in Policy 1 had basically two requirements:
•
Recover from large events less than or equal to MSSC in 15 minutes.
•
Replenish your reserves in 90 minutes such that you can recover from subsequent events.
There was an expectation that the BA made best efforts to recover from larger events as demonstrated by the reporting form that included events >
MSSC and which NERC has tracked over the years. The remainder of the original DCS just explained how the two requirements above were
accomplished in the context of a Reserve Sharing Group as well as provided administrative information to support the standard.
We are layering complexity in this standard at the same time NERC has a major project to streamline and focus the standards. Reliability would be
better served if the standard were simplified under the Standards Efficiency Review process to the following requirements:
•
Recover from Reportable Balancing Contingency Events in 15 minutes.
•
Replenish reserves within 90 minutes as demonstrated by successful recovery from subsequent Reportable Balancing Contingency Events.
•
Make best efforts and report recovery performance for events > MSSC or when reserves are diminished due to other contingencies.
The redline change to the standard has the BA telling the RC something they both already know and also expects the BA during an emergency to
specifically mention two bullets in the standard. It should also be noted that the requirement is basically duplicative of EOP-011 R2.
As mentioned earlier, BAs are still held to the Balancing Authority ACE Limit as well as IROL requirements no matter what the size of the event. NERC
collects DCS performance data for its State of Reliability Report, to include events > MSSC. NERC’s report shows that BA performance has been
stellar. If problems develop in the future, new requirements can be implemented.
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Richard Kinas - Orlando Utilities Commission - 5
Answer
Yes
Document Name
Comment
OUC is concerned that proposed modifications could negatively impact reliability by causing additional actions for the sake of compliance. Additionally,
there seems to be some redundancy with EOP-011-1 2.2.1 which states “Notification to its Reliability Coordinator, to include current and projected
conditions when experiencing a Capacity Emergency or Energy Emergency;”. Having redundancy and overlap in the standards goes against the current
Standards Efficiency Review effort that is underway. OUC agrees with the following comments submitted by MRO:
We have concerns related to the unintended reliability consequences associated with the proposed changes in BAL-002-3 regarding the development
and discussion of plans with the Reliability Coordinator in real time to restore ACE following a contingency during capacity shortages.
One thing that seems to be overlooked is that both the BA and RC have obligations in other standards to take action if a BA’s ACE is negatively
impacting frequency or transmission limits.
The exclusion provisions in the current BAL-002-2 deal with situations where the BA has multiple problems (capacity emergency, previous
contingencies or multiple contingencies). The priorities of a Balancing Authority following multiple contingencies are to:
Assess the incoming alarms and determine the extent of the problem.
Prioritize actions depending on the location of the event, whether there is a frequency issue or what transmission is being negatively impacted.
Direct generators to load to correct ACE or to adjust (in coordination with the Transmission Operator) to manage flows.
Coordinate with its TOP, adjacent BAs, and request assistance from the RC as needed.
There can be dozens of actions taking place in a matter of 10-15 minutes.
The role of the Reliability Coordinator is not to manage or approve the local actions taken by the Balancing Authority. The proposed changes would put
two sets of hands on the wheel and delay action. This is the equivalent of asking the pilot upon the loss of an engine to map out actions and reach out
to the air traffic controller to discuss the pilot’s proposal.
The role of the RC is to assist the BA as needed and point out external issues the Balancing Authority might not see. Only if a BA is not taking action
and there are likely adverse reliability impacts should the RC intervene.
The original Disturbance Control Standard (DCS) prior to 2007 had basically two requirements:
Recover from large events less than or equal to MSSC in 15 minutes.
Replenish your reserves in 90 minutes such that you can recover from subsequent events.
There was an expectation that the BA made best efforts to recover from larger events as demonstrated by the reporting form that included events >
MSSC and which NERC has tracked over the years. The remainder of the original DCS just explained how the two requirements above were
accomplished in the context of a Reserve Sharing Group as well as provided administrative information to support the standard.
While BAL-002-0 made the original DCS more complex, any operator could understand the objectives and explain how performance is
demonstrated. The currently enforceable BAL-002-2 is so complex that we believe no two operators asked to explain compliance would come up with
the same answer. Version 3 not only layers complexity in the compliance evaluation; it will distract operators from their primary tasks.
We are layering complexity in this standard at the same time NERC has a major project to streamline and focus the standards. Reliability would be
better served if the standard were simplified under the Standards Efficiency Review process to the following requirements:
Recover from Reportable Balancing Contingency Events in 15 minutes.
Replenish reserves within 90 minutes as demonstrated by successful recovery from subsequent Reportable Balancing Contingency Events.
Make best efforts and report recovery performance for events > MSSC or when reserves are diminished due to other contingencies.
As mentioned earlier, BAs are still held to the Balancing Authority ACE Limit as well as IROL requirements no matter what the size of the event. NERC
collects DCS performance data for its State of Reliability Report, to include events > MSSC. NERC’s report shows that BA performance has been
stellar. If problems develop in the future, new requirements can be implemented.
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Brandon McCormick - Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 6, 4, 3, 5; Chris Gowder, Florida
Municipal Power Agency, 6, 4, 3, 5; David Owens, Gainesville Regional Utilities, 3, 1, 5; Ginny Beigel, City of Vero Beach, 3; Joe McKinney,
Florida Municipal Power Agency, 6, 4, 3, 5; Ken Simmons, Gainesville Regional Utilities, 3, 1, 5; Mike Blough, Kissimmee Utility Authority, 5,
3; Richard Montgomery, Florida Municipal Power Agency, 6, 4, 3, 5; Tom Reedy, Florida Municipal Power Pool, 6; - Brandon McCormick,
Group Name FMPA
Answer
Yes
Document Name
Comment
FMPA is concerned that proposed modifications could negatively impact reliability by causing additional actions for the sake of
compliance. Additionally, there seems to be some redundancy with EOP-011-1 2.2.1 which states “Notification to its Reliability Coordinator, to include
current and projected conditions when experiencing a Capacity Emergency or Energy Emergency;”. Having redundancy and overlap in the standards
goes against the current Standards Efficiency Review effort that is underway. FMPA agrees with the following comments submitted by MRO:
We have concerns related to the unintended reliability consequences associated with the proposed changes in BAL-002-3 regarding the development
and discussion of plans with the Reliability Coordinator in real time to restore ACE following a contingency during capacity shortages.
One thing that seems to be overlooked is that both the BA and RC have obligations in other standards to take action if a BA’s ACE is negatively
impacting frequency or transmission limits.
The exclusion provisions in the current BAL-002-2 deal with situations where the BA has multiple problems (capacity emergency, previous
contingencies or multiple contingencies). The priorities of a Balancing Authority following multiple contingencies are to:
Assess the incoming alarms and determine the extent of the problem.
Prioritize actions depending on the location of the event, whether there is a frequency issue or what transmission is being negatively
impacted.
Direct generators to load to correct ACE or to adjust (in coordination with the Transmission Operator) to manage flows.
Coordinate with its TOP, adjacent BAs, and request assistance from the RC as needed.
There can be dozens of actions taking place in a matter of 10-15 minutes.
The role of the Reliability Coordinator is not to manage or approve the local actions taken by the Balancing Authority. The proposed changes would put
two sets of hands on the wheel and delay action. This is the equivalent of asking the pilot upon the loss of an engine to map out actions and reach out
to the air traffic controller to discuss the pilot’s proposal.
The role of the RC is to assist the BA as needed and point out external issues the Balancing Authority might not see. Only if a BA is not taking action
and there are likely adverse reliability impacts should the RC intervene.
The original Disturbance Control Standard (DCS) prior to 2007 had basically two requirements:
{C}·
Recover from large events less than or equal to MSSC in 15 minutes.
{C}·
Replenish your reserves in 90 minutes such that you can recover from subsequent events.
There was an expectation that the BA made best efforts to recover from larger events as demonstrated by the reporting form that included events >
MSSC and which NERC has tracked over the years. The remainder of the original DCS just explained how the two requirements above were
accomplished in the context of a Reserve Sharing Group as well as provided administrative information to support the standard.
While BAL-002-0 made the original DCS more complex, any operator could understand the objectives and explain how performance is
demonstrated. The currently enforceable BAL-002-2 is so complex that we believe no two operators asked to explain compliance would come up with
the same answer. Version 3 not only layers complexity in the compliance evaluation; it will distract operators from their primary tasks.
We are layering complexity in this standard at the same time NERC has a major project to streamline and focus the standards. Reliability would be
better served if the standard were simplified under the Standards Efficiency Review process to the following requirements:
Recover from Reportable Balancing Contingency Events in 15 minutes.
Replenish reserves within 90 minutes as demonstrated by successful recovery from subsequent Reportable Balancing Contingency Events.
Make best efforts and report recovery performance for events > MSSC or when reserves are diminished due to other contingencies.
As mentioned earlier, BAs are still held to the Balancing Authority ACE Limit as well as IROL requirements no matter what the size of the event. NERC
collects DCS performance data for its State of Reliability Report, to include events > MSSC. NERC’s report shows that BA performance has been
stellar. If problems develop in the future, new requirements can be implemented.
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0
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0
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Shelby Wade - PPL - Louisville Gas and Electric Co. - 1,3,5,6 - SERC,RF, Group Name PPL NERC Registered Affiliates
Answer
Document Name
Comment
Yes
PPL NERC Registered Affiliates suggests that NERC post a complete redline of Proposed Reliability Standard BAL-002-3 to ensure the industry is fully
aware of the transition of the Supplemental Material to a Technical Rationale document. The Redline to Last Approved Version of Proposed Reliability
Standard BAL-002-3 posted to the NERC project page on March 22, 2018 is not a complete redline as it does not show the removal of the
“Supplemental Material” (also known as Technical Rationale), which is currently included in the effective version BAL-002-2(i).
Furthermore, the document entitled “Rationales for BAL-002-3” should be entitled “Technical Rationale for BAL-002-3” in accordance with the NERC
Technical Rationale for Reliability Standards Policy, and a redline to the last version of this document approved by industry should also be posted.
Additionally, the document entitled “Rationales for BAL-002-3” seems to include implementation guidance as it states “Requirement R1 does not apply
when…”.
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0
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0
Response
Cynthia Kneisl - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
We have concerns related to the unintended reliability consequences associated with the proposed changes in BAL-002-3 regarding the development
and discussion of plans with the Reliability Coordinator in real time to restore ACE following a contingency during capacity shortages.
One thing that seems to be overlooked is that both the BA and RC have obligations in other standards to take action if a BA’s ACE is negatively
impacting frequency or transmission limits.
The exclusion provisions in the current BAL-002-2 deal with situations where the BA has multiple problems (capacity emergency, previous
contingencies or multiple contingencies). The priorities of a Balancing Authority following multiple contingencies are to:
•
•
•
•
Assess the incoming alarms and determine the extent of the problem.
Prioritize actions depending on the location of the event, whether there is a frequency issue or what transmission is being negatively impacted.
Direct generators to load to correct ACE or to adjust (in coordination with the Transmission Operator) to manage flows.
Coordinate with its TOP, adjacent BAs, and request assistance from the RC as needed.
There can be dozens of actions taking place in a matter of 10-15 minutes.
The role of the Reliability Coordinator is not to manage or approve the local actions taken by the Balancing Authority. The proposed changes would put
two sets of hands on the wheel and delay action. This is the equivalent of asking the pilot upon the loss of an engine to map out actions and reach out
to the air traffic controller to discuss the pilot’s proposal.
The role of the RC is to assist the BA as needed and point out external issues the Balancing Authority might not see. Only if a BA is not taking action
and there are likely adverse reliability impacts should the RC intervene.
The original Disturbance Control Standard (DCS) prior to 2007 had basically two requirements:
•
•
Recover from large events less than or equal to MSSC in 15 minutes.
Replenish your reserves in 90 minutes such that you can recover from subsequent events.
There was an expectation that the BA made best efforts to recover from larger events as demonstrated by the reporting form that included events >
MSSC and which NERC has tracked over the years. The remainder of the original DCS just explained how the two requirements above were
accomplished in the context of a Reserve Sharing Group as well as provided administrative information to support the standard.
While BAL-002-0 made the original DCS more complex, any operator could understand the objectives and explain how performance is
demonstrated. The currently enforceable BAL-002-2 is so complex that we believe no two operators asked to explain compliance would come up with
the same answer. Version 3 not only layers complexity in the compliance evaluation; it will distract operators from their primary tasks.
We are layering complexity in this standard at the same time NERC has a major project to streamline and focus the standards. Reliability would be
better served if the standard were simplified under the Standards Efficiency Review process to the following requirements:
•
•
•
Recover from Reportable Balancing Contingency Events in 15 minutes.
Replenish reserves within 90 minutes as demonstrated by successful recovery from subsequent Reportable Balancing Contingency Events.
Make best efforts and report recovery performance for events > MSSC or when reserves are diminished due to other contingencies.
As mentioned earlier, BAs are still held to the Balancing Authority ACE Limit as well as IROL requirements no matter what the size of the event. NERC
collects DCS performance data for its State of Reliability Report, to include events > MSSC. NERC’s report shows that BA performance has been
stellar. If problems develop in the future, new requirements can be implemented.
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0
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Michelle Amarantos - APS - Arizona Public Service Co. - 1
Answer
Yes
Document Name
Comment
Since it is necessary for a Balancing Authority to be in the conditions described in the first three bullets and have communicated those conditions to
their Reliability Coordinator in order to be declared in an EEA, it is not necessary to repeat those steps in the proposed language in the fourth bullet of
1.3.1. The resulting fourth bullet would then read “has provided the Reliability Coordinator with an ACE recovery plan, including target recovery time
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0
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Kevin Salsbury - Berkshire Hathaway - NV Energy - 5
Answer
Document Name
Comment
Yes
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0
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0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
It appears that this version needs some clean-up prior to the final version. Texas RE noticed the following:
•
The grammatical structure of Requirement 1 Part 1.3 is unclear as to whether the bullets are just for the RSG or the BA as well.
•
In the “Rationales” document there is a reference to changes in definition of Contingency Reserve “in the posting” but it does not specify which
posting.
•
Texas RE requests to see a draft updated CR Form 1 since it is an associated document in Section F of the standard. Will this form be housed
with the related documents?
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0
Consideration of Comments
Project Name:
2017‐06 Modifications to BAL‐002‐2 | BAL‐002‐3
Comment Period Start Date:
3/22/2018
Comment Period End Date:
5/8/2018
Associated Ballot:
2017‐06 Modifications to BAL‐002‐2 BAL‐002‐3 IN 1 ST
There were 30 sets of responses, including comments from approximately 115 different people from approximately 87 companies
representing the 10 Industry Segments as shown in the table on the following pages.
The Standard Drafting Team (SDT) scope was to address FERC’s (Commission) requirements as listed in Order No. 835. The Commission
stated in Order No. 835 it was concerned with a Balancing Authority operating out‐of‐balance for an extended period of time and is
“leaning on the system” by relying on external resources to meet its obligations. Therefore, the Commission directed NERC to develop
modifications to BAL‐002‐2 Requirement 1 to require balancing authorities: (1) to notify the reliability coordinator of the conditions set
forth in Requirement R1, Part 1.3.1 preventing it from complying with the 15‐minute ACE recovery period; and (2) to provide the reliability
coordinator with the ACE recovery plan, including a target recovery time. The SDT took careful consideration to assure that fulfillment of
this requirement could occur during communications with its Reliability Coordinator in accordance with the Energy Emergency Alert
procedures.
Requirement R1, Part 1.3 addresses qualifying for exemption from Requirement R1 Part 1.1 and all conditions listed in Requirement R1,
Part 1.3.1 must be met in order to qualify for the exemption. One of the conditions, is the BA is experiencing a Reliability Coordinator
declared Energy Emergency Alert (EEA) Level. When a BA is experiencing a declared Energy emergency Alert level, it is communicating
with its RC the conditions and its expected time to recover, which is basically addressing when a BA is out‐of‐balance and is “leaning on the
system”. By requiring an ACE recovery plan, the BA is providing the RC its expected time to recover and would no longer experiencing an
EEA.
The SDT did not believe providing an ACE recovery plan place an onerous requirement on the BA, since under an EEA it requires the BA to
provide to the RC such information.
Finally, to restate Requirement R1, Part 1.3 addresses qualifying for exemption from Requirement R1 Part 1.1. Since all conditions of
Requirement R1, Part 1.3.1 must be met in order to qualify for exemption, the SDT expects exemption to be very rare. However, for the
Responsible Entity to qualify for exemption, it must meet all conditions:
the Responsible Entity: is (i) a Balancing Authority or (ii) a Reserve Sharing Group with at least one member that:
is experiencing a Reliability Coordinator declared Energy Emergency Alert Level, and
is utilizing its Contingency Reserve to mitigate an operating emergency in accordance with its emergency Operating
Plan, and
has depleted its Contingency Reserve to a level below its Most Severe Single Contingency, and
has, during communications with its Reliability Coordinator in accordance with the Energy Emergency Alert
procedures: (i) notified the Reliability Coordinator of the conditions described in the preceding two bullet points
preventing the Responsible Entity from complying with Requirement R1 part 1.1 , and (ii) provided the Reliability
Coordinator with an ACE recovery plan, including target recovery time.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact Senior Director, Standards and Education
Howard Gugel (via email) or at (404) 446‐9693.
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
2
Questions
1. The SDT has modified Requirement R1 to address the Commission’s concerns identified in FERC Order 835. Do you agree that the
proposed modifications clearly state the intentions of the SAR? If not, please state your concerns and provide specific language on
the proposed revision.
2. Do you have any other comments for drafting team consideration?
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load‐serving Entities
4 — Transmission‐dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
3
Organization
Name
Name
Brandon
Brandon
McCormick McCormick
Segment(s)
Region
FRCC
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
Group Member
Group Name
Name
FMPA
Group
Member
Organization
Group
Group Member
Member
Region
Segment(s)
Tim Beyrle
City of New 4
Smyrna Beach
Utilities
Commission
FRCC
Jim Howard
Lakeland
Electric
5
FRCC
Lynne Mila
City of
Clewiston
4
FRCC
Javier Cisneros Fort Pierce
Utilities
Authority
3
FRCC
Randy Hahn
Ocala Utility
Services
3
FRCC
Don Cuevas
Beaches
Energy
Services
1
FRCC
Jeffrey
Partington
Keys Energy
Services
4
FRCC
Tom Reedy
Florida
Municipal
Power Pool
6
FRCC
4
Organization
Name
Name
ACES Power Brian Van
Marketing Gheem
Segment(s)
6
Region
NA ‐ Not
Applicable
Group Name
Group Member
Name
Group
Group Member
Member
Region
Segment(s)
Steven
Lancaster
Beaches
Energy
Services
3
FRCC
Mike Blough
Kissimmee
Utility
Authority
5
FRCC
Chris Adkins
City of
Leesburg
3
FRCC
Ginny Beigel
City of Vero
Beach
3
FRCC
ACES
Greg Froehling Rayburn
3
Standards
Country
Collaborators
Electric
Cooperative,
Inc.
Bob Solomon
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
Group
Member
Organization
Hoosier
1
Energy Rural
Electric
Cooperative,
Inc.
SPP RE
RF
Ginger Mercier Prairie Power, 1,3
Inc.
SERC
John Shaver
WECC
Arizona
1
Electric Power
5
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member
Name
Group
Member
Organization
Group
Group Member
Member
Region
Segment(s)
Cooperative,
Inc.
Duke Energy Colby Bellville 1,3,5,6
Michael
Brytowski
Great River
Energy
Bill Hutchison
Southern
1
Illinois Power
Cooperative
SERC
Duke Energy 1
RF
Duke Energy 3
FRCC
Dale Goodwine Duke Energy 5
SERC
Greg Cecil
Duke Energy 6
RF
Joseph
DePoorter
Madison Gas 3,4,5,6
& Electric
MRO
Larry Heckert
Alliant Energy 4
MRO
Amy Casucelli
Xcel Energy
1,3,5,6
MRO
Michael
Brytowski
Great River
Energy
1,3,5,6
MRO
Jodi Jensen
Western Area 1,6
Power
Administration
MRO
Kayleigh
Wilkerson
Lincoln
Electric
System
MRO
FRCC,RF,SERC Duke Energy Doug Hils
Lee Schuster
MRO
Cynthia Kneisl 1,2,3,4,5,6
MRO
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
MRO NSRF
1,3,5,6
5
MRO
6
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member
Name
Kayleigh
Wilkerson
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
Group
Member
Organization
Lincoln
Electric
System
Group
Group Member
Member
Region
Segment(s)
1,3,5,6
MRO
Mahmood Safi Omaha Public 1,3,5,6
Power District
MRO
Brad Parret
Minnesota
Power
1,5
MRO
Terry Harbour
MidAmerican 1,3
Energy
Corporation
MRO
Tom Breene
Wisconsin
3,4,5
Public Service
MRO
Jeremy Voll
Basin Electric 1
Power
Cooperative
MRO
Kevin Lyons
Central Iowa
Power
Cooperative
1
MRO
MIke Morrow
Midcontinent 2
Independent
System
Operator
MRO
7
Organization
Name
Tennessee
Valley
Authority
Name
Dennis
Chastain
Southern
Katherine
Company ‐ Prewitt
Southern
Company
Services, Inc.
Segment(s)
1,3,5,6
1
Region
SERC
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
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Group Name
Tennessee
Valley
Authority
Southern
Company
Group Member
Name
Group
Member
Organization
Group
Group Member
Member
Region
Segment(s)
Andy Fuhrman Minnkota
Power
Cooperative
1
MRO
DeWayne Scott Tennessee
Valley
Authority
1
SERC
Ian Grant
Tennessee
Valley
Authority
3
SERC
Brandy Spraker Tennessee
Valley
Authority
5
SERC
Marjorie
Parsons
Tennessee
Valley
Authority
6
SERC
Scott Moore
Alabama
Power
Company
3
SERC
Bill Shultz
Southern
Company
Generation
5
SERC
Jennifer Sykes
Southern
Company
Generation
6
SERC
8
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member
Name
Group
Member
Organization
Group
Group Member
Member
Region
Segment(s)
and Energy
Marketing
Tennessee
Valley
Authority
M Lee
Thomas
Northeast
Ruida Shu
Power
Coordinating
Council
5
1,2,3,4,5,6,7,8,9,10 NPCC
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
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Tennessee
Valley
Authority
RSC no
Dominion
and NYISO
Howell Scott
Tennessee
Valley
Authority
1
SERC
Ian Grant
Tennessee
Valley
Authority
3
SERC
M Lee Thomas Tennessee
Valley
Authority
5
SERC
Marjorie
Parsons
Tennessee
Valley
Authority
6
SERC
Guy V. Zito
Northeast
10
Power
Coordinating
Council
NPCC
Randy
MacDonald
New
Brunswick
Power
2
NPCC
Wayne Sipperly New York
Power
Authority
4
NPCC
9
Organization
Name
Name
Segment(s)
Region
Group Name
Group Member
Name
Glen Smith
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
Group
Member
Organization
Entergy
Services
Group
Group Member
Member
Region
Segment(s)
4
NPCC
Brian Robinson Utility Services 5
NPCC
Alan Adamson
New York
State
Reliability
Council
7
NPCC
Edward Bedder Orange &
Rockland
Utilities
1
NPCC
David Burke
3
NPCC
Michele Tondalo UI
1
NPCC
Laura Mcleod
NB Power
1
NPCC
David
Ramkalawan
Ontario Power 5
Generation
Inc.
NPCC
Helen Lainis
IESO
2
NPCC
Michael
Schiavone
National Grid 1
NPCC
Michael Jones
National Grid 3
NPCC
Orange &
Rockland
Utilities
10
Organization
Name
Name
Segment(s)
Region
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
Group Name
Group Member
Name
Group
Member
Organization
Group
Group Member
Member
Region
Segment(s)
Michael Forte
Con Ed ‐
1
Consolidated
Edison
NPCC
Peter Yost
Con Ed ‐
3
Consolidated
Edison Co. of
New York
NPCC
Sean Cavote
PSEG
4
NPCC
Kathleen
Goodman
ISO‐NE
2
NPCC
Paul Malozewski Hydro One
3
Networks, Inc.
NPCC
Quintin Lee
NPCC
Eversource
Energy
1
Dermot Smyth Con Ed ‐
1,5
Consolidated
Edison Co. of
New York
NPCC
Dermot Smyth Con Ed ‐
1,5
Consolidated
Edison Co. of
New York
NPCC
11
Organization
Name
Dominion ‐
Dominion
Resources,
Inc.
Name
Sean Bodkin 6
Segment(s)
Region
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
Group Name
Dominion
Group Member
Name
Group
Member
Organization
Group
Group Member
Member
Region
Segment(s)
Salvatore
Spagnolo
New York
Power
Authority
1
NPCC
Shivaz Chopra
New York
Power
Authority
6
NPCC
David Kiguel
Independent NA ‐ Not
Applicable
NPCC
Silvia Mitchell
NextEra
6
Energy ‐
Florida Power
and Light Co.
NPCC
Caroline Dupuis Hydro Quebec 1
NPCC
Chantal Mazza Hydro Quebec 2
NPCC
Connie Lowe
Dominion ‐
Dominion
Resources,
Inc.
3
NA ‐ Not
Applicable
Lou Oberski
Dominion ‐
Dominion
Resources,
Inc.
5
NA ‐ Not
Applicable
12
Organization
Name
Name
Southwest Shannon
Power Pool, Mickens
Inc. (RTO)
Segment(s)
2
Region
SPP RE
Group Name
SPP
Standards
Review
Group
Group Member
Name
Group
Member
Organization
Larry Nash
Dominion ‐
1
Dominion
Virginia Power
NA ‐ Not
Applicable
Shannon
Mickens
Southwest
Power Pool
Inc.
2
SPP RE
Don Schmit
Nebraska
5
Public Power
District
SPP RE
Robert Hirchak Cleco
Corporation
PPL ‐
Shelby Wade 1,3,5,6
Louisville Gas
and Electric
Co.
RF,SERC
6
SPP RE
Charlie Freibert LG&E and KU 3
Energy, LLC
SERC
Brenda Truhe
PPL Electric
Utilities
Corporation
RF
Dan Wilson
LG&E and KU 5
Energy, LLC
SERC
Linn Oelker
LG&E and KU 6
Energy, LLC
SERC
1
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
PPL NERC
Registered
Affiliates
Group
Group Member
Member
Region
Segment(s)
13
1. The SDT has modified Requirement R1 to address the Commission’s concerns identified in FERC Order 835. Do you agree that the
proposed modifications clearly state the intentions of the SAR? If not, please state your concerns and provide specific language on the
proposed revision.
Cynthia Kneisl ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO, Group Name MRO NSRF
Answer
No
Document Name
Comment
While the SAR and the proposed changes address the stated FERC directive from one perspective, NERC is authorized to propose an
equally effective alternative to achieve the reliability objective. We believe the approach in the draft standard could negatively impact
reliability.
Our comments below outline issues with the standard and the direction it is taking. The change will distract operators from their primary
tasks in order to develop and discuss a plan following a contingency during an Energy Emergency Alert (EEA).
The provisions being changed deal with exclusions to compliance. We believe the better path is for the drafting team to work with NERC
(with input from the NERC OC) to create Implementation Guidance and a companion CMEP Practice Guide that outlines approaches for
multi‐contingent events, events > Most Severe Single Contingencies, and for ERO Compliance Staff to handle Reportable Balancing
Contingency Events (RBCEs) during EEAs.
We also believe there is more to gain from a reliability perspective to pass these rare events through the Events Analysis process to create
lessons‐learned.
Finally, if the drafting team rejects our comments, we believe the change should be limited to: “Notified the RC that they have
experienced a Reportable Balancing Contingency Event (RBCE) in cases where the BA expects recovery to take > 30 minutes and provided
proposed actions and an expected recovery time.”
Likes 0
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
14
Dislikes 0
Response
Thank you for your comment. Since we are dealing with an exemption to the standard, provisions associated with the exemption must be
included within the standard. Therefore the SDT modified the standard in accordance with the FERC direction including FERC provisions.
With regards to your comment concerning event analysis the SDT agrees and believes that all EEA declarations are reported and analyzed
by the event analysis group.
An entity must meet all of the specific conditions to qualify for the exemption, and the ACE recovery plan is only required for the
exemption.
Leonard Kula ‐ Independent Electricity System Operator ‐ 2
Answer
No
Document Name
Comment
While the proposed changes appear to clearly state the intention of the SAR, certain parts appear to be redundant with some of the
existing requirements while other parts seem unnecessary if an alternative means, such as an exception to compliance, is developed.
Firstly, Point (i) in the forth bullet under Part 1.3.1 is unnecessary:
1. The first bullet under Part 1.3.1 implies that a BA’s RC is already aware of the EEA declaration (since it makes that declaration
itself!)
2. The RC is already notified of its BA’s emergency condition via EOP‐011, Requirement R2 (Part 2.2.1).
Secondly, regarding Point (ii) in Part 1.3.1, a BA’s priority under either an EEA or a capacity or energy emergency is to mitigate the
emergency condition to return the BA Area to normal state. Developing and notifying its RC a plan to recover ACE under either
condition should not be a priority as such a task may actually jeopardize reliability. A BA should be allowed time to manage its EEA
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
15
and/or emergency. Only when such issues are duly addressed and the BA is out of EEA and/or emergency should it be required to
notify its RC of an ACE recovery plan, including target recovery time, or the actions being undertaken to recover ACE.
We therefore urge the SDT to seek an alternative means (such as an exception to compliance) to meet the FERC directive on providing
an ACE recovery plan, or to create a Part 1.4 that will require a BA to notify its RC of an ACE recovery plan, including target recovery
time or its actions being undertaken to recover ACE, after it has recovered from an EEA or a capacity or energy emergency.
Likes 0
Dislikes 0
Response
Thank you for your comment. ACE recovery plans are just one provision associated with exemption. Since FERC directed us to include
this provision in the standard, the BA must meet all provisions to obtain exemption to Requirement R1. It’s up to the BA to provide the
ACE recovery plan to qualify for the exemption.
Brandon McCormick ‐ Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 6, 4, 3, 5; Chris Gowder, Florida
Municipal Power Agency, 6, 4, 3, 5; David Owens, Gainesville Regional Utilities, 3, 1, 5; Ginny Beigel, City of Vero Beach, 3; Joe
McKinney, Florida Municipal Power Agency, 6, 4, 3, 5; Ken Simmons, Gainesville Regional Utilities, 3, 1, 5; Mike Blough, Kissimmee
Utility Authority, 5, 3; Richard Montgomery, Florida Municipal Power Agency, 6, 4, 3, 5; Tom Reedy, Florida Municipal Power Pool, 6; ‐
Brandon McCormick, Group Name FMPA
Answer
No
Document Name
Comment
: FMPA is concerned that the proposed modifications could potentially be a distraction for operators and negatively impact reliability. We
agree with the following comments submitted by MRO:
While the SAR and the proposed changes address the stated FERC directive from one perspective, NERC is authorized to propose an
equally effective alternative to achieve the reliability objective. We believe the approach in the draft standard could negatively impact
reliability.
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
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16
Our comments below outline issues with the standard and the direction it is taking. The change will distract operators from their primary
tasks in order to develop and discuss a plan following a contingency during an Energy Emergency Alert (EEA).
The provisions being changed deal with exclusions to compliance. We believe the better path is for the drafting team to work with NERC
(with input from the NERC OC) to create Implementation Guidance and a companion CMEP Practice Guide that outlines approaches for
multi‐contingent events, events > Most Severe Single Contingencies, and for ERO Compliance Staff to handle Reportable Balancing
Contingency Events (RBCEs) during EEAs.
We also believe there is more to gain from a reliability perspective to pass these rare events through the Events Analysis process to create
lessons‐learned.
Finally, if the drafting team rejects our comments, we believe the change should be limited to: “Notified the RC that they have
experienced a Reportable Balancing Contingency Event (RBCE) in cases where the BA expects recovery to take > 30 minutes and provided
proposed actions and an expected recovery time.”
Likes 0
Dislikes 0
Response
Thank you for your comment. Since we are dealing with an exemption to the standard, provisions associated with the exemption must be
included within the standard. Therefore the SDT modified the standard in accordance with the FERC direction including FERC provisions.
With regards to your comment concerning event analysis, the SDT agrees and believes that all EEA declarations are reported and analyzed
by the event analysis group.
An entity must meet all of the specific conditions to qualify for the exemption, and the ACE recovery plan is only required for the
exemption.
Richard Kinas ‐ Orlando Utilities Commission ‐ 5
Answer
No
Document Name
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
17
Comment
OUC is concerned that the proposed modifications could potentially be a distraction for operators and negatively impact reliability. We
agree with the following comments submitted by MRO:
While the SAR and the proposed changes address the stated FERC directive from one perspective, NERC is authorized to propose an
equally effective alternative to achieve the reliability objective. We believe the approach in the draft standard could negatively impact
reliability.
Our comments below outline issues with the standard and the direction it is taking. The change will distract operators from their primary
tasks in order to develop and discuss a plan following a contingency during an Energy Emergency Alert (EEA).
The provisions being changed deal with exclusions to compliance. We believe the better path is for the drafting team to work with NERC
(with input from the NERC OC) to create Implementation Guidance and a companion CMEP Practice Guide that outlines approaches for
multi‐contingent events, events > Most Severe Single Contingencies, and for ERO Compliance Staff to handle Reportable Balancing
Contingency Events (RBCEs) during EEAs.
We also believe there is more to gain from a reliability perspective to pass these rare events through the Events Analysis process to create
lessons‐learned.
Finally, if the drafting team rejects our comments, we believe the change should be limited to: “Notified the RC that they have
experienced a Reportable Balancing Contingency Event (RBCE) in cases where the BA expects recovery to take > 30 minutes and provided
proposed actions and an expected recovery time.”
Likes 0
Dislikes 0
Response
Thank you for your comment. Since we are dealing with an exemption to the standard, provisions associated with the exemption must be
included within the standard. Therefore the SDT modified the standard in accordance with the FERC direction including FERC provisions.
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
18
With regards to your comment concerning event analysis, the SDT agrees and believes that all EEA declarations are reported and analyzed
by the event analysis group.
An entity must meet all of the specific conditions to qualify for the exemption, and the ACE recovery plan is only required for the
exemption.
Richard Vine ‐ California ISO ‐ 2
Answer
No
Document Name
Comment
While the SAR and the proposed changes address the stated FERC directive from one perspective, NERC is authorized to propose an
equally effective alternative. We believe the approach in the draft standard could negatively impact reliability.
Our comments below outline issues with the standard and the direction it is taking. The change will distract operators from their primary
tasks in order to develop and discuss a plan following a contingency during an EEA.
The provisions being changed deal with exclusions to compliance. We believe the better path is for the drafting team to work with NERC
(with input from the NERC OC) to create a CMEP Practice Guide that outlines an approach for ERO Compliance Staff to handle RBCEs
during these situations.
We also believe there is more to gain from a reliability perspective to pass these rare events through the Events Analysis process to create
lessons‐learned.
Finally, if the drafting team rejects our comments, we believe the change should be limited to: “Notified the RC that they have
experienced a Reportable Balancing Contingency Event (RBCE) and provided an expected recovery time”.
Likes 0
Dislikes 0
Response
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
19
Thank you for your comment. Since we are dealing with an exemption to the standard, provisions associated with the exemption must be
included within the standard. Therefore the SDT modified the standard in accordance with the FERC direction including FERC provisions.
With regards to your comment concerning event analysis, the SDT agrees and believes that all EEA declarations are reported and analyzed
by the event analysis group.
An entity must meet all of the specific conditions to qualify for the exemption, and the ACE recovery plan is only required for the
exemption.
Dennis Chastain ‐ Tennessee Valley Authority ‐ 1,3,5,6 ‐ SERC, Group Name Tennessee Valley Authority
Answer
No
Document Name
Comment
We believe that the conditions set forth in the first requirement of the FERC order are already accomplished through the requirements in
EOP‐011 for declaring an EEA 3 and should not be restated here in BAL‐002. A BA experiencing the conditions set forth in the first three
bullets in R1.3.1 is by definition experiencing EEA 3 conditions and the required communication to the RC is satisfied through the request
to declare an EEA 3. Restating them in this standard could lead to conflicts between the standards as they evolve over time. We are also
concerned that the current language in the draft could cause a delay in recovery from an event as the contingent BA’s time is occupied
creating a detailed level of audit evidence documenting the official recovery plan and recovery time estimate during the Recovery Period
of the event and then communicating those to the RC. This would only serve to prolong the threat to the BES caused by the supply
shortage which occurred as a result of the contingency.
Likes 0
Dislikes 0
Response
Thank you for your comment. FERC directed the SDT to include this provision as one of the conditions for exemption. The SDT took
extreme care to assure we referenced the provisions within the Energy Emergency Alert procedures.
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
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20
David Jendras ‐ Ameren ‐ Ameren Services ‐ 3
Answer
No
Document Name
Comment
Ameren believes that any Requirement for actions an entity is required to take when experiencing an RC declared EEA level belongs in
EOP‐011, Emergency Operations.
In lieu thereof, Ameren believes the following BAL‐002‐3 language would be an acceptable alternative to meet the intent and spirit of
the FERC directive, until a revision of EOP‐011‐1 occurs as described below:
In addition to the redline changes for R1.3 and R1.3.1, Ameren suggests adding the additional bullets as stated below:
•provide updates to the ACE recovery plan, including target recovery time, to its Reliability Coordinator, during its
communications with the RC as required in "Attachment 1‐EOP‐011‐1 Energy Emergency Alerts"
•and implements the ACE recovery plan when given an Operating Instruction to do so by its RC.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT scope was associated with only the FERC Order associated with BAL‐002. This SDT is not able to
change the EEA procedure which would require a new or revised SAR.
ACE recovery plans are just one provision associated with exemption. Since FERC directed us to include this provision in the standard, the
BA must meet all provisions to obtain exemption to Requirement R1. It’s up to the BA to provide the ACE recovery plan to qualify for the
exemption.
M Lee Thomas ‐ Tennessee Valley Authority ‐ 5, Group Name Tennessee Valley Authority
Answer
No
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
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21
Document Name
Comment
TVA believes that the conditions set forth in the 1st requirement of the FERC order are already accomplished through the requirements in
EOP‐011 for declaring an EEA 3 and should not be restated here in BAL‐002. A BA experiencing the conditions set forth in the first three
bullets in R1.3.1 is by definition experiencing EEA 3 conditions and the required communication to the RC is satisfied through the request
to declare an EEA 3. Restating them in this standard could lead to conflicts between the standards as they evolve over time. We are also
concerned that the current language in the draft could cause a delay in recovery from an event as the contingent BA’s time is occupied
creating a detailed level of audit evidence documenting the official recovery plan and recovery time estimate during the Recovery Period
of the event and then communicating those to the RC. This would only serve to prolong the threat to the BES caused by the supply
shortage which occurred as a result of the contingency.
Likes 0
Dislikes 0
Response
Thank you for your comment. FERC directed the SDT to include this provision as one of the conditions for exemption. The SDT took
extreme care to assure we referenced the provisions within the Energy Emergency Alert procedures.
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7,8,9,10 ‐ NPCC, Group Name RSC no Dominion and NYISO
Answer
No
Document Name
Comment
While the proposed changes appear to clearly state the intention of the SAR, certain parts appear to be redundant with some of the
existing requirements while other parts seem unnecessary if an alternative means, such as an exception to compliance, is developed.
Firstly, Point (i) in the forth bullet under Part 1.3.1 is unnecessary:
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1. The first bullet under Part 1.3.1 implies that a BA’s RC is already aware of the EEA declaration (since it makes that declaration
itself!)
2. The RC is already notified of its BA’s emergency condition via EOP‐011, Requirement R2 (Part 2.2.1).
Secondly, regarding Point (ii) in Part 1.3.1, a BA’s priority under either an EEA or a capacity or energy emergency is to mitigate the
emergency condition to return the BA Area to normal state. Developing and notifying its RC a plan to recover ACE under either condition
should not be a priority as such a task may actually jeopardize reliability. A BA should be allowed time to manage its EEA and/or
emergency. Only when such issues are duly addressed and the BA is out of EEA and/or emergency should it be required to notify its RC of
an ACE recovery plan, including target recovery time, or the actions being undertaken to recover ACE.
We therefore urge the SDT to seek an alternative means (such as an exception to compliance) to meet the FERC directive on providing an
ACE recovery plan, or to create a Part 1.4 that will require a BA to notify its RC of an ACE recovery plan, including target recovery time or
its actions being undertaken to recover ACE, after it has recovered from an EEA or a capacity or energy emergency.
Likes 0
Dislikes 0
Response
Thank you for your comment. ACE recovery plans are just one provision associated with exemption. Since FERC directed us to include
this provision in the standard, the BA must meet all provisions to obtain exemption to Requirement R1. It’s up to the BA to provide the
ACE recovery plan to qualify for the exemption.
FERC directed the SDT to include this provision as one of the conditions for exemption. The SDT took extreme care to assure we
referenced the provisions within the Energy Emergency Alert procedures.
Brian Van Gheem ‐ ACES Power Marketing ‐ 6, Group Name ACES Standards Collaborators
Answer
No
Document Name
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Comment
1. We believe the proposed reference to “preceding two bullet points” should be clarified, as compliance with this requirement can
be confusing. Very few NERC Reliability Requirements identify an action and then follow that with an exemption to the action
based on a specific condition. The proposed changes are made to the exemption portion of the requirement, which already
implies that compliance with Requirement R1 part 1.1 is unnecessary. The embedded dual condition within the proposed bullet
should be split to provide clarity. One bullet should identify the inhibitive reasoning provided to the RC from the distressed BA or
RSG that is unable to restore its ACE to the appropriate Pre‐Reporting Contingency Event ACE Value within the Contingency Event
Recovery Period. The second bullet should also identify that the ACE recovery plan was provided to the RC.
2. The reference to “recovery time” should be replaced with the appropriate NERC Glossary Term, Contingency Event Recovery
Period.
Likes 0
Dislikes 0
Response
Thank you for your comment. An entity must meet all of the specified conditions to qualify for the exemption, and the ACE recovery plan
is only required for the exemption.
With respect to your suggestion to split the fourth bullet, the SDT believes the condition as written must be a single bullet to maintain
continuity within the bullet.
Recovery time is an undefined term when dealing with the exemption and is variable when dealing with individual ACE recovery plans.
Maryanne Darling‐Reich ‐ Black Hills Corporation ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
N/A to BHC
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Likes 0
Dislikes 0
Response
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
BPA suggests rewording of “an ACE recovery plan” to “actions it will take to recover its ACE”. BPA believes this rewording will help R1
sound less like a defined term which will depend on or require additional documentation. BPA’s concern is that “an ACE recovery plan”
will be assumed to be an additional document such as the Emergency Operating Plan.
Likes 0
Dislikes 0
Response
Thank you for your affirmative response and clarifying comment. The SDT took the wording directly from the FERC order.
Neil Swearingen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer
Yes
Document Name
Comment
SRP supports the proposed revisions.
Likes 0
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Dislikes 0
Response
Thank you for your affirmative response and clarifying comment.
Yvonne McMackin ‐ Public Utility District No. 2 of Grant County, Washington ‐ 4
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Glen Farmer ‐ Avista ‐ Avista Corporation ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Kevin Salsbury ‐ Berkshire Hathaway ‐ NV Energy ‐ 5
Answer
Yes
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Document Name
Comment
Likes 0
Dislikes 0
Response
Scott Langston ‐ Tallahassee Electric (City of Tallahassee, FL) ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Michelle Amarantos ‐ APS ‐ Arizona Public Service Co. ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
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Response
Ozan Ferrin ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Shelby Wade ‐ PPL ‐ Louisville Gas and Electric Co. ‐ 1,3,5,6 ‐ SERC,RF, Group Name PPL NERC Registered Affiliates
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
Yes
Document Name
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Comment
Likes 0
Dislikes 0
Response
Colby Bellville ‐ Duke Energy ‐ 1,3,5,6 ‐ FRCC,SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Sean Bodkin ‐ Dominion ‐ Dominion Resources, Inc. ‐ 6, Group Name Dominion
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
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Richard Jackson ‐ U.S. Bureau of Reclamation ‐ 1
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Wendy Center ‐ U.S. Bureau of Reclamation ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Selene Willis ‐ Edison International ‐ Southern California Edison Company ‐ 1,3,5,6
Answer
Yes
Document Name
Comment
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Likes 0
Dislikes 0
Response
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Katherine Prewitt ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1, Group Name Southern Company
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
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Kristine Ward ‐ Seminole Electric Cooperative, Inc. ‐ 1,3,4,5 ‐ FRCC
Answer
Document Name
Comment
N/a
Likes 0
Dislikes 0
Response
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
Document Name
Comment
The SDT may wish to clarify when the ACE recovery plan must be submitted for a BA to qualify for the exemption. The proposed BAL‐002‐
3 R 1.3 now specifies that a BA may be exempt from BAL‐002‐3 R1.1 if it has “during communications with its Reliability Coordinator in
accordance with the Energy Emergency Alert procedure” notified the RC of conditions preventing it from responding and “provided the
Reliability Coordinator with an ACE recovery plan, including target recovery time.”
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT believes that the entire recovery time frame is the period in which the BA is to notify the RC of its
ACE recovery plan. During your discussions with the RC to declare an EEA the BA must provide all information associated with the
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emergency including the estimated period of the potential EEA and must update the RC hourly or upon a change of EEA status until the
EEA is terminated. Part of the discussion with the RC to qualify for the exemption under BAL‐002 will include your ACE recovery plan and
the target recovery time. An entity must meet all of the specified conditions to qualify for the exemption, and the ACE recovery plan is
only required for the exemption.
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2. Do you have any other comments for drafting team consideration?
Brian Van Gheem ‐ ACES Power Marketing ‐ 6, Group Name ACES Standards Collaborators
Answer
No
Document Name
Comment
We thank you for this opportunity to comment.
Likes 0
Dislikes 0
Response
Neil Swearingen ‐ Salt River Project ‐ 1,3,5,6 ‐ WECC
Answer
No
Document Name
Comment
No additional comments.
Likes 0
Dislikes 0
Response
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Katherine Prewitt ‐ Southern Company ‐ Southern Company Services, Inc. ‐ 1, Group Name Southern Company
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Ruida Shu ‐ Northeast Power Coordinating Council ‐ 1,2,3,4,5,6,7,8,9,10 ‐ NPCC, Group Name RSC no Dominion and NYISO
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Selene Willis ‐ Edison International ‐ Southern California Edison Company ‐ 1,3,5,6
Answer
No
Document Name
Comment
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Likes 0
Dislikes 0
Response
David Jendras ‐ Ameren ‐ Ameren Services ‐ 3
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Wendy Center ‐ U.S. Bureau of Reclamation ‐ 5
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Richard Jackson ‐ U.S. Bureau of Reclamation ‐ 1
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Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Colby Bellville ‐ Duke Energy ‐ 1,3,5,6 ‐ FRCC,SERC,RF, Group Name Duke Energy
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Laura Nelson ‐ IDACORP ‐ Idaho Power Company ‐ 1
Answer
No
Document Name
Comment
Likes 0
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Dislikes 0
Response
Ozan Ferrin ‐ Tacoma Public Utilities (Tacoma, WA) ‐ 5
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Scott Langston ‐ Tallahassee Electric (City of Tallahassee, FL) ‐ 1
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Aaron Cavanaugh ‐ Bonneville Power Administration ‐ 1,3,5,6 ‐ WECC
Answer
No
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Document Name
Comment
Likes 0
Dislikes 0
Response
Glen Farmer ‐ Avista ‐ Avista Corporation ‐ 5
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Kristine Ward ‐ Seminole Electric Cooperative, Inc. ‐ 1,3,4,5 ‐ FRCC
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
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Response
Yvonne McMackin ‐ Public Utility District No. 2 of Grant County, Washington ‐ 4
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
Maryanne Darling‐Reich ‐ Black Hills Corporation ‐ 1,3,5,6 ‐ WECC
Answer
No
Document Name
Comment
Likes 0
Dislikes 0
Response
M Lee Thomas ‐ Tennessee Valley Authority ‐ 5, Group Name Tennessee Valley Authority
Answer
Yes
Document Name
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Comment
TVA believes that given the amount of actions BA’s are required to make during a Reportable Disturbance, and the very short window of
time allowed in the standard to successfully complete those actions, that the Standards should not put additional regulatory burden on
the operators to create documentation and notifications during this window. This small amount of time should be dedicated to restoring
the BES to a stable condition. It is also important to note that the contingent BA is still subject to the BAAL limit during a contingency any
time the BES is threatened with a negative supply balance; therefore, the BA still has a compliance obligation to restore its balance
anytime the interconnection is threatened even if the BA is not subject to compliance under BAL‐002. Given the small amount of
Contingency Reserves available to the BA in this situation and the degree of time urgency, the BA should make every effort to recover its
imbalance and deploy all remaining Contingency Reserves in order to recover as much imbalance as possible. Only once those actions are
completed should the BA focus on communicating the recovery plan and target recovery time to the RC, and this should not be required
to be within the Recovery Period in order to be granted a waiver from compliance under BAL‐002.
The proposed revision should be based on BAL‐002‐2(i), which is the last approved and currently effective version.
Likes 0
Dislikes 0
Response
Thank you for your comment. ACE recovery plans are just one provision associated with exemption. Since FERC directed us to include
this provision in the standard, the BA must meet all provisions to obtain exemption to Requirement R1. It’s up to the BA to provide the
ACE recovery plan to qualify for the exemption.
Shannon Mickens ‐ Southwest Power Pool, Inc. (RTO) ‐ 2 ‐ SPP RE, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
The SPP Standards Review Group suggests that the drafting team provide clarity on the intent of the proposed language pertaining to
Requirement R1 Part 1.3.1. The proposed language in BAL‐002 (Part 1.3.1) is addressing entities that would be in an EEA 3 knowing that
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they wouldn’t return to an acceptable status in the required 15 minutes. Looking at EOP‐011, any entity that is in an EEA 3 per
Attachment 1, that entity would have to report their status to the Reliability Coordinator (RC) every hour. To our understanding, the
entity being identified in BAL‐002 (Part 1.3.1‐which would be in an EEA 3 situation and would not be in compliance) could make their
report in that same hour until they return to an acceptable status. We ask the drafting team to clarify whether there is connection
between the required actions of these two standards. If the drafting team agrees with our understanding, we would suggest that the
drafting team include some language discussing the connection of both standards in BAL‐002‐3. This would provide clarity on the
expectations of entities that don’t recover in the required 15 minutes as well as being in an EEA 3 condition.
Likes 0
Dislikes 0
Response
Thank you for your comment. ACE recovery plans are just one provision associated with exemption. Since FERC directed us to include
this provision in the standard, the BA must meet all provisions to obtain exemption to Requirement R1. It’s up to the BA to provide the
ACE recovery plan to qualify for the exemption.
The SDT took extreme care to assure we referenced the provisions within the Energy Emergency Alert procedures.
Dennis Chastain ‐ Tennessee Valley Authority ‐ 1,3,5,6 ‐ SERC, Group Name Tennessee Valley Authority
Answer
Yes
Document Name
Comment
We believe that given the amount of actions BA’s are required to make during a Reportable Disturbance, and the very short window of
time allowed in the standard to successfully complete those actions, that the Standards should not put additional regulatory burden on
the operators to create documentation and notifications during this window. This small amount of time should be dedicated to restoring
the BES to a stable condition. It is also important to note that the contingent BA is still subject to the BAAL limit during a contingency any
time the BES is threatened with a negative supply balance; therefore, the BA still has a compliance obligation to restore its balance
anytime the interconnection is threatened even if the BA is not subject to compliance under BAL‐002. Given the small amount of
Contingency Reserves available to the BA in this situation and the degree of time urgency, the BA should make every effort to recover its
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imbalance and deploy all remaining Contingency Reserves in order to recover as much imbalance as possible. Only once those actions are
completed should the BA focus on communicating the recovery plan and target recovery time to the RC, and this should not be required
to be within the Recovery Period in order to be granted a waiver from compliance under BAL‐002.
The proposed revision should be based on BAL‐002‐2(i), which is the last approved and currently effective version.
Likes 0
Dislikes 0
Response
Thank you for your comment. ACE recovery plans are just one provision associated with exemption. Since FERC directed us to include
this provision in the standard, the BA must meet all provisions to obtain exemption to Requirement R1. It’s up to the BA to provide the
ACE recovery plan to qualify for the exemption.
The SDT took extreme care to assure we referenced the provisions within the Energy Emergency Alert procedures.
Sean Bodkin ‐ Dominion ‐ Dominion Resources, Inc. ‐ 6, Group Name Dominion
Answer
Yes
Document Name
Comment
Dominion Energy has a concern regarding the Technical Rationale document. It appears that SDT has transitioned the existing GTB
document to a Technical Rationale document without completely addressing all of the compliance langugae contained in the document.
"Requirement R1 does not apply when an entity experiences a Balancing Contingency Event that exceeds its MSSC (which includes
multiple Balancing Contingency Events as described in R1 part 1.3.2 below) because a fundamental goal of the SDT is to assure the
Responsible Entity has enough flexibility to maintain service to Demand while managing reliability."
This first example states when an entity does not have to comply and the standard is not applicable. It is not intent, it is a statement that
directly impacts compliance. While the latter section of the section does state what the intent of the SDT was when developing the
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language and, in isolation would be appropriate for the TR document, the former part of the statement is not appropriate for the TR
document. Just because a statement is not a specific example of how to comply does not render it appropriate for the TR document.
"In addition, the drafting team has added language to R 1.3.1 clarifying that if a BA is experiencing an EEA event underwhich its
contingency reserve has been activated, the RSG in which it resides would also be considered to be exempt from R1 compliance."
The second quotation also makes a specific compliance statement, exempting a specific entity from compliance of the Requirement.
While not an ‘example’ that could be directly ported to an IG document, it is compliance language that is not appropriate for a TR
document. As stated before, just because compliance language does not fit the definition of IG does not render it appropriate for TR.
"Under the Energy Emergency Alert procedures, the BA must inform the RC of the conditions and necessary requirements to meet
reliability and the RC must approve of the information being provided before issuing an Energy Emergency Alert."
The third quotation is a statement that clearly states how to comply with the EEA process. Once again, while not specific IG that
statement is not appropriate for a TR document.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT will consider your comments and make associated modifications, if necessary.
Richard Vine ‐ California ISO ‐ 2
Answer
Yes
Document Name
Comment
We have concerns related to the unintended reliability consequences associated with the proposed changes in BAL‐002‐3 regarding the
development and discussion of plans with the Reliability Coordinator in real time to restore ACE following a contingency during capacity
shortages.
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One thing that seems to be overlooked is that both the BA and RC have obligations in other standards to take action if a BA’s ACE is
negatively impacting frequency or transmission limits.
The exclusion provisions in the current BAL‐002‐2 deal with situations where the BA has multiple problems (capacity emergency, previous
contingencies or multiple contingencies). Under these situations the BA may likely need to perform dozens of tasks in a 15 minute
period.
The role of the Reliability Coordinator is not to manage or approve the local actions taken by the Balancing Authority. The proposed
changes would put two sets of hands on the wheel and delay action. This is the equivalent of asking the pilot upon the loss of an engine
to map out actions and reach out to the air traffic controller to discuss the pilot’s proposal.
The original Disturbance Control Standard (DCS) in Policy 1 had basically two requirements:
Recover from large events less than or equal to MSSC in 15 minutes.
Replenish your reserves in 90 minutes such that you can recover from subsequent events.
There was an expectation that the BA made best efforts to recover from larger events as demonstrated by the reporting form that
included events > MSSC and which NERC has tracked over the years. The remainder of the original DCS just explained how the two
requirements above were accomplished in the context of a Reserve Sharing Group as well as provided administrative information to
support the standard.
We are layering complexity in this standard at the same time NERC has a major project to streamline and focus the standards. Reliability
would be better served if the standard were simplified under the Standards Efficiency Review process to the following requirements:
Recover from Reportable Balancing Contingency Events in 15 minutes.
Replenish reserves within 90 minutes as demonstrated by successful recovery from subsequent Reportable Balancing Contingency
Events.
Make best efforts and report recovery performance for events > MSSC or when reserves are diminished due to other
contingencies.
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The redline change to the standard has the BA telling the RC something they both already know and also expects the BA during an
emergency to specifically mention two bullets in the standard. It should also be noted that the requirement is basically duplicative of
EOP‐011 R2.
As mentioned earlier, BAs are still held to the Balancing Authority ACE Limit as well as IROL requirements no matter what the size of the
event. NERC collects DCS performance data for its State of Reliability Report, to include events > MSSC. NERC’s report shows that BA
performance has been stellar. If problems develop in the future, new requirements can be implemented.
Likes 0
Dislikes 0
Response
Thank you for your comment. ACE recovery plans are just one provision associated with an exemption. Since FERC directed us to include
this provision in the standard, the BA must meet all provisions to obtain exemption to Requirement R1. It’s up to the BA to provide the
ACE recovery plan to qualify for the exemption.
All other standards are still applicable such as BAL‐001, IROLs, etc. and it is up to the BA to address these other standards with the RC.
Richard Kinas ‐ Orlando Utilities Commission ‐ 5
Answer
Yes
Document Name
Comment
OUC is concerned that proposed modifications could negatively impact reliability by causing additional actions for the sake of
compliance. Additionally, there seems to be some redundancy with EOP‐011‐1 2.2.1 which states “Notification to its Reliability
Coordinator, to include current and projected conditions when experiencing a Capacity Emergency or Energy Emergency;”. Having
redundancy and overlap in the standards goes against the current Standards Efficiency Review effort that is underway. OUC agrees with
the following comments submitted by MRO:
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We have concerns related to the unintended reliability consequences associated with the proposed changes in BAL‐002‐3 regarding the
development and discussion of plans with the Reliability Coordinator in real time to restore ACE following a contingency during capacity
shortages.
One thing that seems to be overlooked is that both the BA and RC have obligations in other standards to take action if a BA’s ACE is
negatively impacting frequency or transmission limits.
The exclusion provisions in the current BAL‐002‐2 deal with situations where the BA has multiple problems (capacity emergency, previous
contingencies or multiple contingencies). The priorities of a Balancing Authority following multiple contingencies are to:
Assess the incoming alarms and determine the extent of the problem.
Prioritize actions depending on the location of the event, whether there is a frequency issue or what transmission is being negatively
impacted.
Direct generators to load to correct ACE or to adjust (in coordination with the Transmission Operator) to manage flows.
Coordinate with its TOP, adjacent BAs, and request assistance from the RC as needed.
There can be dozens of actions taking place in a matter of 10‐15 minutes.
The role of the Reliability Coordinator is not to manage or approve the local actions taken by the Balancing Authority. The proposed
changes would put two sets of hands on the wheel and delay action. This is the equivalent of asking the pilot upon the loss of an engine
to map out actions and reach out to the air traffic controller to discuss the pilot’s proposal.
The role of the RC is to assist the BA as needed and point out external issues the Balancing Authority might not see. Only if a BA is not
taking action and there are likely adverse reliability impacts should the RC intervene.
The original Disturbance Control Standard (DCS) prior to 2007 had basically two requirements:
Recover from large events less than or equal to MSSC in 15 minutes.
Replenish your reserves in 90 minutes such that you can recover from subsequent events.
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There was an expectation that the BA made best efforts to recover from larger events as demonstrated by the reporting form that
included events > MSSC and which NERC has tracked over the years. The remainder of the original DCS just explained how the two
requirements above were accomplished in the context of a Reserve Sharing Group as well as provided administrative information to
support the standard.
While BAL‐002‐0 made the original DCS more complex, any operator could understand the objectives and explain how performance is
demonstrated. The currently enforceable BAL‐002‐2 is so complex that we believe no two operators asked to explain compliance would
come up with the same answer. Version 3 not only layers complexity in the compliance evaluation; it will distract operators from their
primary tasks.
We are layering complexity in this standard at the same time NERC has a major project to streamline and focus the standards. Reliability
would be better served if the standard were simplified under the Standards Efficiency Review process to the following requirements:
Recover from Reportable Balancing Contingency Events in 15 minutes.
Replenish reserves within 90 minutes as demonstrated by successful recovery from subsequent Reportable Balancing Contingency Events.
Make best efforts and report recovery performance for events > MSSC or when reserves are diminished due to other contingencies.
As mentioned earlier, BAs are still held to the Balancing Authority ACE Limit as well as IROL requirements no matter what the size of the
event. NERC collects DCS performance data for its State of Reliability Report, to include events > MSSC. NERC’s report shows that BA
performance has been stellar. If problems develop in the future, new requirements can be implemented.
Likes 0
Dislikes 0
Response
Thank you for your comment. ACE recovery plans are just one provision associated with an exemption. Since FERC directed us to include
this provision in the standard, the BA must meet all provisions to obtain exemption to Requirement R1. It’s up to the BA to provide the
ACE recovery plan to qualify for the exemption.
All other standards are still applicable such as BAL‐001, IROLs, etc. and it is up to the BA to address these other standards with the RC.
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Brandon McCormick ‐ Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 6, 4, 3, 5; Chris Gowder, Florida
Municipal Power Agency, 6, 4, 3, 5; David Owens, Gainesville Regional Utilities, 3, 1, 5; Ginny Beigel, City of Vero Beach, 3; Joe
McKinney, Florida Municipal Power Agency, 6, 4, 3, 5; Ken Simmons, Gainesville Regional Utilities, 3, 1, 5; Mike Blough, Kissimmee
Utility Authority, 5, 3; Richard Montgomery, Florida Municipal Power Agency, 6, 4, 3, 5; Tom Reedy, Florida Municipal Power Pool, 6; ‐
Brandon McCormick, Group Name FMPA
Answer
Yes
Document Name
Comment
FMPA is concerned that proposed modifications could negatively impact reliability by causing additional actions for the sake of
compliance. Additionally, there seems to be some redundancy with EOP‐011‐1 2.2.1 which states “Notification to its Reliability
Coordinator, to include current and projected conditions when experiencing a Capacity Emergency or Energy Emergency;”. Having
redundancy and overlap in the standards goes against the current Standards Efficiency Review effort that is underway. FMPA agrees with
the following comments submitted by MRO:
We have concerns related to the unintended reliability consequences associated with the proposed changes in BAL‐002‐3 regarding the
development and discussion of plans with the Reliability Coordinator in real time to restore ACE following a contingency during capacity
shortages.
One thing that seems to be overlooked is that both the BA and RC have obligations in other standards to take action if a BA’s ACE is
negatively impacting frequency or transmission limits.
The exclusion provisions in the current BAL‐002‐2 deal with situations where the BA has multiple problems (capacity emergency, previous
contingencies or multiple contingencies). The priorities of a Balancing Authority following multiple contingencies are to:
Assess the incoming alarms and determine the extent of the problem.
Prioritize actions depending on the location of the event, whether there is a frequency issue or what transmission is being
negatively impacted.
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
49
Direct generators to load to correct ACE or to adjust (in coordination with the Transmission Operator) to manage flows.
Coordinate with its TOP, adjacent BAs, and request assistance from the RC as needed.
There can be dozens of actions taking place in a matter of 10‐15 minutes.
The role of the Reliability Coordinator is not to manage or approve the local actions taken by the Balancing Authority. The proposed
changes would put two sets of hands on the wheel and delay action. This is the equivalent of asking the pilot upon the loss of an engine
to map out actions and reach out to the air traffic controller to discuss the pilot’s proposal.
The role of the RC is to assist the BA as needed and point out external issues the Balancing Authority might not see. Only if a BA is not
taking action and there are likely adverse reliability impacts should the RC intervene.
The original Disturbance Control Standard (DCS) prior to 2007 had basically two requirements:
{C}∙ Recover from large events less than or equal to MSSC in 15 minutes.
{C}∙ Replenish your reserves in 90 minutes such that you can recover from subsequent events.
There was an expectation that the BA made best efforts to recover from larger events as demonstrated by the reporting form that
included events > MSSC and which NERC has tracked over the years. The remainder of the original DCS just explained how the two
requirements above were accomplished in the context of a Reserve Sharing Group as well as provided administrative information to
support the standard.
While BAL‐002‐0 made the original DCS more complex, any operator could understand the objectives and explain how performance is
demonstrated. The currently enforceable BAL‐002‐2 is so complex that we believe no two operators asked to explain compliance would
come up with the same answer. Version 3 not only layers complexity in the compliance evaluation; it will distract operators from their
primary tasks.
We are layering complexity in this standard at the same time NERC has a major project to streamline and focus the standards. Reliability
would be better served if the standard were simplified under the Standards Efficiency Review process to the following requirements:
Recover from Reportable Balancing Contingency Events in 15 minutes.
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
50
Replenish reserves within 90 minutes as demonstrated by successful recovery from subsequent Reportable Balancing Contingency Events.
Make best efforts and report recovery performance for events > MSSC or when reserves are diminished due to other contingencies.
As mentioned earlier, BAs are still held to the Balancing Authority ACE Limit as well as IROL requirements no matter what the size of the
event. NERC collects DCS performance data for its State of Reliability Report, to include events > MSSC. NERC’s report shows that BA
performance has been stellar. If problems develop in the future, new requirements can be implemented.
Likes 0
Dislikes 0
Response
Thank you for your comment. ACE recovery plans are just one provision associated with an exemption. Since FERC directed us to include
this provision in the standard, the BA must meet all provisions to obtain exemption to Requirement R1. It’s up to the BA to provide the
ACE recovery plan to qualify for the exemption.
All other standards are still applicable such as BAL‐001, IROLs, etc. and it is up to the BA to address these other standards with the RC.
Shelby Wade ‐ PPL ‐ Louisville Gas and Electric Co. ‐ 1,3,5,6 ‐ SERC,RF, Group Name PPL NERC Registered Affiliates
Answer
Yes
Document Name
Comment
PPL NERC Registered Affiliates suggests that NERC post a complete redline of Proposed Reliability Standard BAL‐002‐3 to ensure the
industry is fully aware of the transition of the Supplemental Material to a Technical Rationale document. The Redline to Last Approved
Version of Proposed Reliability Standard BAL‐002‐3 posted to the NERC project page on March 22, 2018 is not a complete redline as it
does not show the removal of the “Supplemental Material” (also known as Technical Rationale), which is currently included in the
effective version BAL‐002‐2(i).
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
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51
Furthermore, the document entitled “Rationales for BAL‐002‐3” should be entitled “Technical Rationale for BAL‐002‐3” in accordance
with the NERC Technical Rationale for Reliability Standards Policy, and a redline to the last version of this document approved by industry
should also be posted.
Additionally, the document entitled “Rationales for BAL‐002‐3” seems to include implementation guidance as it states “Requirement R1
does not apply when…”.
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT will pass your comment on the the appropriate NERC staff.
Cynthia Kneisl ‐ MRO ‐ 1,2,3,4,5,6 ‐ MRO, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
We have concerns related to the unintended reliability consequences associated with the proposed changes in BAL‐002‐3 regarding the
development and discussion of plans with the Reliability Coordinator in real time to restore ACE following a contingency during capacity
shortages.
One thing that seems to be overlooked is that both the BA and RC have obligations in other standards to take action if a BA’s ACE is
negatively impacting frequency or transmission limits.
The exclusion provisions in the current BAL‐002‐2 deal with situations where the BA has multiple problems (capacity emergency, previous
contingencies or multiple contingencies). The priorities of a Balancing Authority following multiple contingencies are to:
Assess the incoming alarms and determine the extent of the problem.
Prioritize actions depending on the location of the event, whether there is a frequency issue or what transmission is being
negatively impacted.
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
52
Direct generators to load to correct ACE or to adjust (in coordination with the Transmission Operator) to manage flows.
Coordinate with its TOP, adjacent BAs, and request assistance from the RC as needed.
There can be dozens of actions taking place in a matter of 10‐15 minutes.
The role of the Reliability Coordinator is not to manage or approve the local actions taken by the Balancing Authority. The proposed
changes would put two sets of hands on the wheel and delay action. This is the equivalent of asking the pilot upon the loss of an engine
to map out actions and reach out to the air traffic controller to discuss the pilot’s proposal.
The role of the RC is to assist the BA as needed and point out external issues the Balancing Authority might not see. Only if a BA is not
taking action and there are likely adverse reliability impacts should the RC intervene.
The original Disturbance Control Standard (DCS) prior to 2007 had basically two requirements:
Recover from large events less than or equal to MSSC in 15 minutes.
Replenish your reserves in 90 minutes such that you can recover from subsequent events.
There was an expectation that the BA made best efforts to recover from larger events as demonstrated by the reporting form that
included events > MSSC and which NERC has tracked over the years. The remainder of the original DCS just explained how the two
requirements above were accomplished in the context of a Reserve Sharing Group as well as provided administrative information to
support the standard.
While BAL‐002‐0 made the original DCS more complex, any operator could understand the objectives and explain how performance is
demonstrated. The currently enforceable BAL‐002‐2 is so complex that we believe no two operators asked to explain compliance would
come up with the same answer. Version 3 not only layers complexity in the compliance evaluation; it will distract operators from their
primary tasks.
We are layering complexity in this standard at the same time NERC has a major project to streamline and focus the standards. Reliability
would be better served if the standard were simplified under the Standards Efficiency Review process to the following requirements:
Recover from Reportable Balancing Contingency Events in 15 minutes.
Replenish reserves within 90 minutes as demonstrated by successful recovery from subsequent Reportable Balancing Contingency
Events.
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
53
Make best efforts and report recovery performance for events > MSSC or when reserves are diminished due to other
contingencies.
As mentioned earlier, BAs are still held to the Balancing Authority ACE Limit as well as IROL requirements no matter what the size of the
event. NERC collects DCS performance data for its State of Reliability Report, to include events > MSSC. NERC’s report shows that BA
performance has been stellar. If problems develop in the future, new requirements can be implemented.
Likes 0
Dislikes 0
Response
Thank you for your comment. ACE recovery plans are just one provision associated with an exemption. Since FERC directed us to include
this provision in the standard, the BA must meet all provisions to obtain exemption to Requirement R1. It’s up to the BA to provide the
ACE recovery plan to qualify for the exemption.
All other standards are still applicable such as BAL‐001, IROLs, etc. and it is up to the BA to address these other standards with the RC.
Michelle Amarantos ‐ APS ‐ Arizona Public Service Co. ‐ 1
Answer
Yes
Document Name
Comment
Since it is necessary for a Balancing Authority to be in the conditions described in the first three bullets and have communicated those
conditions to their Reliability Coordinator in order to be declared in an EEA, it is not necessary to repeat those steps in the proposed
language in the fourth bullet of 1.3.1. The resulting fourth bullet would then read “has provided the Reliability Coordinator with an ACE
recovery plan, including target recovery time
Likes 0
Dislikes 0
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
54
Response
Thank you for your comment. FERC directed the SDT to include this provision as one of the conditions for exemption. The SDT took
extreme care to assure we referenced the provisions within the Energy Emergency Alert procedures.
Kevin Salsbury ‐ Berkshire Hathaway ‐ NV Energy ‐ 5
Answer
Yes
Document Name
Comment
Likes 0
Dislikes 0
Response
Rachel Coyne ‐ Texas Reliability Entity, Inc. ‐ 10
Answer
Document Name
Comment
It appears that this version needs some clean‐up prior to the final version. Texas RE noticed the following:
The grammatical structure of Requirement 1 Part 1.3 is unclear as to whether the bullets are just for the RSG or the BA as well.
In the “Rationales” document there is a reference to changes in definition of Contingency Reserve “in the posting” but it does not
specify which posting.
Texas RE requests to see a draft updated CR Form 1 since it is an associated document in Section F of the standard. Will this form
be housed with the related documents?
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
BAL‐002‐3 | Enter Date C of C will be posted here:
55
Likes 0
Dislikes 0
Response
Thank you for your comment. The SDT believes that the current language provides sufficient clarity.
End of Report
Consideration of Comments | Project 2017‐06 Modifications to BAL‐002‐2
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56
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the Board of Trustees.
Description of Current Draft
Completed Actions
SAR posted for comment
Anticipated Actions
Date
06/20/17 – 07/20/17
Date
45‐day formal comment period with initial ballot
February 2018 through
March 2018
10‐day final ballot
April 2018
NERC Board (Board) adoption
May 2018
Draft 1 – BAL‐002‐3
March 2018
Page 1 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
A. Introduction
1.
Title: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
2.
Number:
3.
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.
4.
Applicability:
4.1.
BAL‐002‐3
Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during which the
Balancing Authority is not in active status under the applicable
agreement or governing rules for the Reserve Sharing Group.
4.1.2. Reserve Sharing Group
5.
Effective Date: See the Implementation Plan for BAL‐002‐3.
B. Requirements and Measures
R1.
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
[Violation Risk Factor: High] [Time Horizon: Real‐time Operations]
1.1.
within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
zero (if its Pre‐Reporting Contingency Event ACE Value was positive or
equal to zero); however, any Balancing Contingency Event that occurs
during the Contingency Event Recovery Period shall reduce the required
recovery: (i) beginning at the time of, and (ii) by the magnitude of, such
individual Balancing Contingency Event,
or,
1.2.
Draft 1 – BAL‐002‐3
March 2018
its Pre‐Reporting Contingency Event ACE Value (if its Pre‐Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery
Period shall reduce the required recovery: (i) beginning at the time of, and
(ii) by the magnitude of, such individual Balancing Contingency Event.
document all Reportable Balancing Contingency Events using CR Form 1.
Page 2 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
1.3.
deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if the Responsible Entity:
1.3.1 is (i) a Balancing Authority or (ii) a Reserve Sharing Group with at least
one member that:
is experiencing a Reliability Coordinator declared Energy Emergency
Alert Level, and
is utilizing its Contingency Reserve to mitigate an operating
emergency in accordance with its emergency Operating Plan, and
has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency, and
has, during communications with its Reliability Coordinator in
accordance with the Energy Emergency Alert procedures, (i) notified
the Reliability Coordinator of the conditions described in the
preceding two bullet points preventing the Responsible Entity from
complying with Requirement R1 part 1.1, and (ii) provided the
Reliability Coordinator with an ACE recovery plan, including target
recovery time
or,
1.3.2 the Responsible Entity experiences:
multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or
multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.
M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.
R2. Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe Single
Contingency and make preparations to have Contingency Reserve equal to, or greater
than the Responsible Entity’s Most Severe Single Contingency available for
maintaining system reliability. [Violation Risk Factor: High] [Time Horizon: Operations
Planning]
Draft 1 – BAL‐002‐3
March 2018
Page 3 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
M2. Each Responsible Entity will have the following documentation to show compliance
with Requirement R2:
a dated Operating Process;
evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,
evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency and
that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.
R3. Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency, before
the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
Period resets the beginning of the Contingency Event Recovery Period. [Violation Risk
Factor: Medium] [Time Horizon: Real‐time Operations]
M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
C. Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity, or any
entity as otherwise designated by an Applicable Governmental Authority, in
their respective roles of monitoring and/or enforcing compliance with
mandatory and enforceable Reliability Standards in their respective
jurisdictions.
1.2.
Evidence Retention
The following evidence retention period(s) identify the period of time an entity
is required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full‐time period
since the last audit.
The Responsible Entity shall retain data or evidence to show compliance for the
current year, plus three previous calendar years, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
Draft 1 – BAL‐002‐3
March 2018
Page 4 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.3.
Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated Reliability Standard.
1.4.
Additional Compliance Information
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.
Draft 1 – BAL‐002‐3
March 2018
Page 5 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
Table of Compliance Elements
R#
R1.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Responsible Entity
achieved less than 100% but
at least 90% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period
The Responsible Entity
achieved less than 90% but
at least 80% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 80% but
at least 70% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 70% of
required recovery from a
Reportable Balancing
Contingency Event during
the Contingency Event
Recovery Period.
N/A
The Responsible Entity
developed an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to implement the
Operating Process.
The Responsible Entity failed
to develop an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency.
OR
The Responsible Entity failed
to use CR Form 1 to
document a Reportable
Balancing Contingency
Event.
R2.
The Responsible Entity
developed and implemented
an Operating Process to
determine its Most Severe
Single Contingency and to
have Contingency Reserve
equal to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to maintain
Draft 1 – BAL‐002‐3
March 2018
Page 6 of 8
BAL‐002‐3 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
annually the Operating
Process.
R3.
The Responsible Entity
restored less than 100% but
at least 90% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 90% but
at least 80% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 80% but
at least 70% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event during
the Contingency Event
Restoration Period.
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
CR Form 1
BAL‐002‐3 Rationales
Draft 1 – BAL‐002‐3
March 2018
Page 7 of 8
Supplemental Material
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from
Effective Date
Errata
0
February 14,
2006
Revised graph on page 3, “10
min.” to “Recovery time.”
Removed fourth bullet.
Errata
1
September 9,
2010
Filed petition for revisions to BAL‐
002 Version 1 with the
Commission
Revision
1
January 10, 2011 FERC letter ordered in Docket No.
RD10‐15‐00 approving BAL‐002‐1
1
April 1, 2012
Effective Date of BAL‐002‐1
1a
November 7,
2012
Interpretation adopted by the
NERC Board of Trustees
1a
February 12,
2013
Interpretation submitted to FERC
2
November 5,
2015
Adopted by NERC Board of
Trustees
Complete revision
2
January 19, 2017 FERC Order approved BAL‐002‐2.
Docket No. RM16‐7‐000
2
October 2, 2017
Draft 1 – BAL‐002‐3
March 2018
FERC letter Order issued
approving raising the VRF for
Requirement R1 and R2 from
Medium to High. Docket No.
RD17‐6‐000.
Page 8 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the Board of Trustees.
Description of Current Draft
Completed Actions
SAR posted for comment
Anticipated Actions
Date
06/20/17 – 07/20/17
Date
45‐day formal comment period with initial ballot
February 2018 through
March 2018
10‐day final ballot
April 2018
NERC Board (Board) adoption
May 2018
Draft 1 – BAL‐002‐3
March 2018
Page 1 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
A. Introduction
1.
Title: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
2.
Number:
3.
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.
4.
Applicability:
4.1.
BAL‐002‐32
Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during which the
Balancing Authority is not in active status under the applicable
agreement or governing rules for the Reserve Sharing Group.
4.1.2. Reserve Sharing Group
5.
Effective Date: See the Implementation Plan for BAL‐002‐32.
B. Requirements and Measures
R1.
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
[Violation Risk Factor: High] [Time Horizon: Real‐time Operations]
1.1.
within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
zero (if its Pre‐Reporting Contingency Event ACE Value was positive or
equal to zero); however, any Balancing Contingency Event that occurs
during the Contingency Event Recovery Period shall reduce the required
recovery: (i) beginning at the time of, and (ii) by the magnitude of, such
individual Balancing Contingency Event,
or,
1.2.
Draft 1 – BAL‐002‐3
March 2018
its Pre‐Reporting Contingency Event ACE Value (if its Pre‐Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery
Period shall reduce the required recovery: (i) beginning at the time of, and
(ii) by the magnitude of, such individual Balancing Contingency Event.
document all Reportable Balancing Contingency Events using CR Form 1.
Page 2 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
1.3.
deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if the Responsible Entity:
1.3.1 is (i) a Balancing Authority or (ii) a Reserve Sharing Group with at least
one member thatthe Responsible Entity:
is a Balancing Authority experiencing a Reliability Coordinator
declared Energy Emergency Alert Level or is a Reserve Sharing Group
whose member, or members, are experiencing a Reliability
Coordinator declared Energy Emergency Alert level, and
is utilizing its Contingency Reserve to mitigate an operating
emergency in accordance with its emergency Operating Plan, and
has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency, and
has, during communications with its Reliability Coordinator in
accordance with the Energy Emergency Alert procedures, (i) notified
the Reliability Coordinator of the conditions described in the
preceding two bullet points preventing the Responsible Entity from
complying with Requirement R1 part 1.1, and (ii) provided the
Reliability Coordinator with an ACE recovery plan, including target
recovery time
or,
1.3.2 the Responsible Entity experiences:
multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or
multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.
M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.
R2. Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe Single
Contingency and make preparations to have Contingency Reserve equal to, or greater
than the Responsible Entity’s Most Severe Single Contingency available for
maintaining system reliability. [Violation Risk Factor: High] [Time Horizon: Operations
Planning]
Draft 1 – BAL‐002‐3
March 2018
Page 3 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
M2. Each Responsible Entity will have the following documentation to show compliance
with Requirement R2:
a dated Operating Process;
evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,
evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency and
that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.
R3. Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency, before
the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
Period resets the beginning of the Contingency Event Recovery Period. [Violation Risk
Factor: Medium] [Time Horizon: Real‐time Operations]
M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
C. Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity, or any
entity as otherwise designated by an Applicable Governmental Authority, in
their respective roles of monitoring and/or enforcing compliance with
mandatory and enforceable Reliability Standards in their respective
jurisdictions.
1.2.
Evidence Retention
The following evidence retention period(s) identify the period of time an entity
is required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full‐time period
since the last audit.
The Responsible Entity shall retain data or evidence to show compliance for the
current year, plus three previous calendar years, unless directed by its
Draft 1 – BAL‐002‐3
March 2018
Page 4 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.3.
1.4.
Draft 1 – BAL‐002‐3
March 2018
Compliance Monitoring and Assessment Processes:
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated Reliability Standard.
Additional Compliance Information
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.
Page 5 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
Table of Compliance Elements
R#
R1.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Responsible Entity
achieved less than 100% but
at least 90% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period
The Responsible Entity
achieved less than 90% but
at least 80% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 80% but
at least 70% of required
recovery from a Reportable
Balancing Contingency Event
during the Contingency
Event Recovery Period.
The Responsible Entity
achieved less than 70% of
required recovery from a
Reportable Balancing
Contingency Event during
the Contingency Event
Recovery Period.
N/A
The Responsible Entity
developed an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to implement the
Operating Process.
The Responsible Entity failed
to develop an Operating
Process to determine its
Most Severe Single
Contingency and to have
Contingency Reserve equal
to, or greater than the
Responsible Entity’s Most
Severe Single Contingency.
OR
The Responsible Entity failed
to use CR Form 1 to
document a Reportable
Balancing Contingency
Event.
R2.
The Responsible Entity
developed and implemented
an Operating Process to
determine its Most Severe
Single Contingency and to
have Contingency Reserve
equal to, or greater than the
Responsible Entity’s Most
Severe Single Contingency
but failed to maintain
Draft 1 – BAL‐002‐3
March 2018
Page 6 of 8
BAL‐002‐32 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
annually the Operating
Process.
R3.
The Responsible Entity
restored less than 100% but
at least 90% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 90% but
at least 80% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 80% but
at least 70% of required
Contingency Reserve
following a Reportable
Balancing Contingency Event
during the Contingency
Event Restoration Period.
The Responsible Entity
restored less than 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event during
the Contingency Event
Restoration Period.
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
BAL‐002‐2 Contingency Reserve for Recovery from a Balancing Contingency Event Background Document
CR Form 1
BAL‐002‐3 Rationales
Draft 1 – BAL‐002‐3
March 2018
Page 7 of 8
Supplemental Material
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from
Effective Date
Errata
0
February 14,
2006
Revised graph on page 3, “10
min.” to “Recovery time.”
Removed fourth bullet.
Errata
1
September 9,
2010
Filed petition for revisions to BAL‐
002 Version 1 with the
Commission
Revision
1
January 10, 2011 FERC letter ordered in Docket No.
RD10‐15‐00 approving BAL‐002‐1
1
April 1, 2012
Effective Date of BAL‐002‐1
1a
November 7,
2012
Interpretation adopted by the
NERC Board of Trustees
1a
February 12,
2013
Interpretation submitted to FERC
2
November 5,
2015
Adopted by NERC Board of
Trustees
Complete revision
2
January 19, 2017 FERC Order approved BAL‐002‐2.
Docket No. RM16‐7‐000
2
October 2, 2017
Draft 1 – BAL‐002‐3
March 2018
FERC letter Order issued
approving raising the VRF for
Requirement R1 and R2 from
Medium to High. Docket No.
RD17‐6‐000.
Page 8 of 8
Implementation Plan
Project 2017-06 Modifications to BAL-002-2
Requested Approvals
BAL‐002‐3 Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event
Requested Retirements
BAL‐002‐2 Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event
Applicable Entities
Balancing Authority
Reserve Sharing Group
Effective Date
The effective date for proposed Reliability Standard BAL‐002‐3 is provided below:
Where approval by an applicable governmental authority is required, Reliability Standard BAL‐002‐3
shall become effective the first day of the first calendar quarter that is six (6) calendar months after
the effective date of the applicable governmental authority’s order approving the standards and
terms, or as otherwise provided for by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, Reliability Standard BAL‐
002‐3 shall become effective on the first day of the first calendar quarter that is six (6) calendar
months after the date the standards and terms are adopted by the NERC Board of Trustees, or as
otherwise provided for in that jurisdiction.
Retirement Date
Current NERC Reliability Standards
The existing standard BAL‐002‐2 shall be retired immediately prior to the effective date of the
proposed BAL‐002‐3 standard.
Standards Announcement
Project 2017-06 Modifications to BAL-002-2
Final Ballot Open through July 16, 2018
Now Available
The final ballot for BAL-002-3 Disturbance Control Standard—Contingency Reserve for Recovery from a
Balancing Contingency Event is open through 8 p.m. Eastern, Monday, July 16, 2018.
Balloting
In the final ballot, votes are counted by exception. Votes from the previous ballot are automatically carried
over in the final ballot. Only members of the applicable ballot pools can cast a vote. Ballot pool members
who previously voted have the option to change their vote in the final ballot. Ballot pool members who did
not cast a vote during the previous ballot can vote in the final ballot.
Members of the ballot pool associated with this project can log in and submit their votes by accessing the
Standards Balloting & Commenting System (SBS) here. If you experience difficulty navigating the SBS,
contact Wendy Muller.
•
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 5 p.m. Eastern).
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours for
NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging into their
SBS accounts prior to the last day of a comment/ballot period.
Next Steps
The voting results will be posted and announced after the ballot closes. If approved, the standard will be
submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory authorities.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Principal Technical Advisor, Darrel Richardson (via email), or at
(609) 613-1848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
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NERC Balloting Tool (/)
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BALLOT RESULTS
Ballot Name: 2017-06 Modifications to BAL-002-2 BAL-002-3 FN 2 ST
Voting Start Date: 7/5/2018 9:17:46 AM
Voting End Date: 7/16/2018 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 195
Total Ballot Pool: 231
Quorum: 84.42
Weighted Segment Value: 71.85
Negative
Fraction
w/
Comment
Negative
Votes
w/o
Comment
Abstain
No
Vote
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Segment:
1
54
1
30
0.789
8
0.211
0
10
6
Segment:
2
6
0.4
2
0.2
2
0.2
0
1
1
Segment:
3
50
1
20
0.667
10
0.333
0
10
10
Segment:
4
14
0.9
6
0.6
3
0.3
0
2
3
Segment:
5
54
1
26
0.703
11
0.297
0
9
8
Segment:
6
43
1
21
0.724
8
0.276
0
7
7
Segment:
7
1
0
0
0
0
0
0
0
1
Segment:
8
1
0.1
1
0.1
0
0
0
0
0
Segment:
9
1
0.1
1
0.1
0
0
0
0
0
1
0.1
0
1
0
Segment
Segment: 7
5
0.5
0.6
10
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Page 2 of 13
Segment
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Totals:
231
6.1
112
4.383
43
Negative
Fraction
w/
Comment
Negative
Votes
w/o
Comment
Abstain
No
Vote
1.717
0
40
36
BALLOT POOL MEMBERS
Show All
Segment
entries
Organization
Search: Search
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Allete - Minnesota Power, Inc.
Jamie Monette
Affirmative
N/A
1
Ameren - Ameren Services
Eric Scott
Negative
N/A
1
APS - Arizona Public Service
Co.
Michelle
Amarantos
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Joe Tarantino
Affirmative
N/A
1
BC Hydro and Power
Authority
Patricia
Robertson
Adrian Andreoiu
Affirmative
N/A
1
Berkshire Hathaway Energy MidAmerican Energy Co.
Terry Harbour
Affirmative
N/A
1
Bonneville Power
Administration
Kammy RogersHolliday
Affirmative
N/A
1
Colorado Springs Utilities
Devin Elverdi
Affirmative
N/A
1
Dairyland Power Cooperative
Renee Leidel
None
N/A
1
Duke Energy
Laura Lee
Affirmative
N/A
1
Edison International Southern California Edison
Company
Steven Mavis
Affirmative
N/A
Abstain
N/A
1
Entergy - Entergy Services,
Oliver Burke
Inc.
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Segment
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Page 3 of 13
Voter
1
Exelon
Chris Scanlon
1
Gainesville Regional Utilities
David Owens
1
Great Plains Energy - Kansas
City Power and Light Co.
James McBee
1
Great River Energy
1
Designated
Proxy
Ballot
NERC
Memo
None
N/A
Brandon
McCormick
Negative
N/A
Douglas Webb
Affirmative
N/A
Gordon Pietsch
Negative
N/A
IDACORP - Idaho Power
Company
Laura Nelson
Affirmative
N/A
1
International Transmission
Company Holdings
Corporation
Michael Moltane
Stephanie Burns
Negative
N/A
1
JEA
Ted Hobson
Joe McClung
Affirmative
N/A
1
Lakeland Electric
Larry Watt
Negative
N/A
1
Lincoln Electric System
Danny Pudenz
Abstain
N/A
1
Long Island Power Authority
Robert Ganley
Affirmative
N/A
1
Los Angeles Department of
Water and Power
faranak sarbaz
Affirmative
N/A
1
Lower Colorado River
Authority
William Sanders
None
N/A
1
Manitoba Hydro
Mike Smith
Abstain
N/A
1
MEAG Power
David Weekley
Abstain
N/A
1
Muscatine Power and Water
Andy Kurriger
None
N/A
1
National Grid USA
Michael Jones
Abstain
N/A
1
New York Power Authority
Salvatore
Spagnolo
Abstain
N/A
1
NextEra Energy - Florida
Power and Light Co.
Mike ONeil
Affirmative
N/A
1
NiSource - Northern Indiana
Public Service Co.
Steve Toosevich
Negative
N/A
1
NorthWestern Energy
Belinda Tierney
None
N/A
1
OGE Energy - Oklahoma Gas
and Electric Co.
Terri Pyle
Affirmative
N/A
Scott Miller
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Organization
Page 4 of 13
Voter
Designated
Proxy
Ballot
NERC
Memo
1
OTP - Otter Tail Power
Company
Charles Wicklund
None
N/A
1
Portland General Electric Co.
Nathaniel Clague
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
Negative
N/A
1
PSEG - Public Service
Electric and Gas Co.
Joseph Smith
Affirmative
N/A
1
Public Utility District No. 1 of
Chelan County
Jeff Kimbell
Abstain
N/A
1
Public Utility District No. 1 of
Snohomish County
Long Duong
Affirmative
N/A
1
Sacramento Municipal Utility
District
Arthur Starkovich
Affirmative
N/A
1
Salt River Project
Steven Cobb
Affirmative
N/A
1
Santee Cooper
Chris Wagner
Affirmative
N/A
1
SCANA - South Carolina
Electric and Gas Co.
Tom Hanzlik
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
Affirmative
N/A
1
Seminole Electric
Cooperative, Inc.
Mark Churilla
Abstain
N/A
1
Southern Company Southern Company Services,
Inc.
Katherine Prewitt
Affirmative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City of
Tallahassee, FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley Authority
Howell Scott
Negative
N/A
1
Tri-State G and T Association,
Inc.
Tracy Sliman
Abstain
N/A
1
U.S. Bureau of Reclamation
Richard Jackson
Affirmative
N/A
1
Westar Energy
Allen Klassen
Abstain
N/A
Affirmative
N/A
1
Western Area Power
sean erickson
Administration
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Segment
Organization
Page 5 of 13
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Xcel Energy, Inc.
Dean Schiro
Affirmative
N/A
2
Electric Reliability Council of
Texas, Inc.
Brandon Gleason
Abstain
N/A
2
Independent Electricity
System Operator
Leonard Kula
Negative
N/A
2
ISO New England, Inc.
Michael Puscas
Affirmative
N/A
2
Midcontinent ISO, Inc.
Terry BIlke
Negative
N/A
2
New York Independent
System Operator
Gregory Campoli
None
N/A
2
PJM Interconnection, L.L.C.
Mark Holman
Affirmative
N/A
3
Ameren - Ameren Services
David Jendras
Negative
N/A
3
APS - Arizona Public Service
Co.
Vivian Vo
Affirmative
N/A
3
Avista - Avista Corporation
Scott Kinney
Affirmative
N/A
3
BC Hydro and Power
Authority
Hootan Jarollahi
Affirmative
N/A
3
Berkshire Hathaway Energy MidAmerican Energy Co.
Annette Johnston
Affirmative
N/A
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
City of Vero Beach
Ginny Beigel
Brandon
McCormick
Negative
N/A
3
Cleco Corporation
Michelle Corley
Louis Guidry
Affirmative
N/A
3
CPS Energy
James Grimshaw
None
N/A
3
DTE Energy - Detroit Edison
Company
Karie Barczak
None
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California Edison
Company
Romel Aquino
Affirmative
N/A
3
Exelon
John Bee
None
N/A
None
N/A
3
FirstEnergy - FirstEnergy
Aaron
Corporation
Ghodooshim
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Joshua Eason
Rich Hydzik
Darnez
Gresham
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Segment
Organization
Page 6 of 13
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Florida Municipal Power
Agency
Joe McKinney
Brandon
McCormick
Negative
N/A
3
Gainesville Regional Utilities
Ken Simmons
Brandon
McCormick
Negative
N/A
3
Georgia System Operations
Corporation
Scott McGough
Abstain
N/A
3
Great Plains Energy - Kansas
City Power and Light Co.
John Carlson
Affirmative
N/A
3
Great River Energy
Brian Glover
Negative
N/A
3
Lincoln Electric System
Jason Fortik
None
N/A
3
Los Angeles Department of
Water and Power
Henry (Hank)
Williams
None
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Abstain
N/A
3
MEAG Power
Roger Brand
Abstain
N/A
3
Muscatine Power and Water
Seth Shoemaker
Negative
N/A
3
National Grid USA
Brian Shanahan
Abstain
N/A
3
Nebraska Public Power
District
Tony Eddleman
Abstain
N/A
3
New York Power Authority
David Rivera
Abstain
N/A
3
NiSource - Northern Indiana
Public Service Co.
Aimee Harris
Negative
N/A
3
Ocala Utility Services
Randy Hahn
Negative
N/A
3
OGE Energy - Oklahoma Gas
and Electric Co.
Donald Hargrove
Affirmative
N/A
3
Owensboro Municipal Utilities
Thomas Lyons
Affirmative
N/A
3
Platte River Power Authority
Jeff Landis
Abstain
N/A
3
Portland General Electric Co.
Angela Gaines
Affirmative
N/A
3
PPL - Louisville Gas and
Electric Co.
Charles Freibert
Negative
N/A
3
Public Utility District No. 1 of
Chelan County
Joyce Gundry
Abstain
N/A
None
N/A
3
Puget Sound Energy, Inc.
Lynda Kupfer
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Douglas Webb
Scott Miller
8/14/2018
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Segment
Organization
Page 7 of 13
Voter
3
Rutherford EMC
Tom Haire
3
Sacramento Municipal Utility
District
Nicole Looney
3
Salt River Project
3
Designated
Proxy
Ballot
NERC
Memo
None
N/A
Affirmative
N/A
Robert
Kondziolka
Affirmative
N/A
Santee Cooper
James Poston
Affirmative
N/A
3
SCANA - South Carolina
Electric and Gas Co.
Scott Parker
None
N/A
3
Seattle City Light
Tuan Tran
None
N/A
3
Seminole Electric
Cooperative, Inc.
James Frauen
Abstain
N/A
3
Snohomish County PUD No. 1
Holly Chaney
Affirmative
N/A
3
Southern Company - Alabama
Power Company
Joel Dembowski
Affirmative
N/A
3
Tacoma Public Utilities
(Tacoma, WA)
Marc Donaldson
Affirmative
N/A
3
Tennessee Valley Authority
Ian Grant
Negative
N/A
3
WEC Energy Group, Inc.
Thomas Breene
Affirmative
N/A
3
Westar Energy
Bryan Taggart
Abstain
N/A
3
Xcel Energy, Inc.
Michael Ibold
Affirmative
N/A
4
Alliant Energy Corporation
Services, Inc.
Larry Heckert
Negative
N/A
4
American Public Power
Association
Jack Cashin
Abstain
N/A
4
Austin Energy
Esther Weekes
Affirmative
N/A
4
City of Poplar Bluff
Neal Williams
None
N/A
4
Florida Municipal Power
Agency
Carol Chinn
Negative
N/A
4
Georgia System Operations
Corporation
Andrea Barclay
Abstain
N/A
4
MGE Energy - Madison Gas
and Electric Co.
Joseph DePoorter
Negative
N/A
Joe Tarantino
Brandon
McCormick
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Segment
Organization
Page 8 of 13
Voter
Designated
Proxy
Ballot
NERC
Memo
4
Public Utility District No. 1 of
Snohomish County
John Martinsen
Affirmative
N/A
4
Public Utility District No. 2 of
Grant County, Washington
Yvonne
McMackin
None
N/A
4
Sacramento Municipal Utility
District
Beth Tincher
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Tacoma Public Utilities
(Tacoma, WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian EvansMongeon
None
N/A
4
WEC Energy Group, Inc.
Anthony
Jankowski
Affirmative
N/A
5
Ameren - Ameren Missouri
Sam Dwyer
Negative
N/A
5
APS - Arizona Public Service
Co.
Kelsi Rigby
Affirmative
N/A
5
Austin Energy
Shirley Mathew
Affirmative
N/A
5
Avista - Avista Corporation
Glen Farmer
Affirmative
N/A
5
BC Hydro and Power
Authority
Helen Hamilton
Harding
Affirmative
N/A
5
Berkshire Hathaway - NV
Energy
Kevin Salsbury
Affirmative
N/A
5
Boise-Kuna Irrigation District Lucky Peak Power Plant
Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Scott Winner
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Negative
N/A
5
Choctaw Generation Limited
Partnership, LLLP
Rob Watson
None
N/A
5
City Water, Light and Power
of Springfield, IL
Steve Rose
Affirmative
N/A
5
Dairyland Power Cooperative
Tommy Drea
None
N/A
Joe Tarantino
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Segment
Organization
Page 9 of 13
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Dominion - Dominion
Resources, Inc.
Lou Oberski
None
N/A
5
DTE Energy - Detroit Edison
Company
Jeffrey DePriest
Affirmative
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Exelon
Ruth Miller
None
N/A
5
Florida Municipal Power
Agency
Chris Gowder
Brandon
McCormick
Negative
N/A
5
Great Plains Energy - Kansas
City Power and Light Co.
Harold Wyble
Douglas Webb
Affirmative
N/A
5
Great River Energy
Preston Walsh
Negative
N/A
5
Herb Schrayshuen
Herb
Schrayshuen
Affirmative
N/A
5
JEA
John Babik
Affirmative
N/A
5
Kissimmee Utility Authority
Mike Blough
Negative
N/A
5
Lakeland Electric
Jim Howard
Negative
N/A
5
Lincoln Electric System
Kayleigh
Wilkerson
Abstain
N/A
5
Los Angeles Department of
Water and Power
Donald
Sievertson
Affirmative
N/A
5
Manitoba Hydro
Yuguang Xiao
Abstain
N/A
5
Massachusetts Municipal
Wholesale Electric Company
David Gordon
Abstain
N/A
5
MEAG Power
Steven Grego
Abstain
N/A
5
Muscatine Power and Water
Neal Nelson
Negative
N/A
5
NaturEner USA, LLC
Eric Smith
Affirmative
N/A
5
NB Power Corporation
Laura McLeod
Affirmative
N/A
5
Nebraska Public Power
District
Don Schmit
Abstain
N/A
5
New York Power Authority
Erick Barrios
Abstain
N/A
Negative
N/A
5
NiSource - Northern Indiana
Kathryn Tackett
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Brandon
McCormick
Scott Miller
8/14/2018
Index - NERC Balloting Tool
Segment
Organization
Page 10 of 13
Voter
Designated
Proxy
Ballot
NERC
Memo
5
OGE Energy - Oklahoma Gas
and Electric Co.
John Rhea
None
N/A
5
Omaha Public Power District
Mahmood Safi
None
N/A
5
Orlando Utilities Commission
Richard Kinas
Negative
N/A
5
Platte River Power Authority
Tyson Archie
Abstain
N/A
5
Portland General Electric Co.
Ryan Olson
None
N/A
5
PPL - Louisville Gas and
Electric Co.
JULIE
HOSTRANDER
Negative
N/A
5
Public Utility District No. 1 of
Chelan County
Haley Sousa
Abstain
N/A
5
Public Utility District No. 1 of
Snohomish County
Sam Nietfeld
Affirmative
N/A
5
Sacramento Municipal Utility
District
Susan Oto
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
Santee Cooper
Tommy Curtis
Affirmative
N/A
5
SCANA - South Carolina
Electric and Gas Co.
Alyssa Hubbard
Affirmative
N/A
5
Southern Company Southern Company
Generation
William D. Shultz
Affirmative
N/A
5
Tacoma Public Utilities
(Tacoma, WA)
Ozan Ferrin
Affirmative
N/A
5
Tennessee Valley Authority
M Lee Thomas
Negative
N/A
5
Tri-State G and T Association,
Inc.
Mark Stein
None
N/A
5
U.S. Bureau of Reclamation
Wendy Center
Affirmative
N/A
5
WEC Energy Group, Inc.
Linda Horn
Affirmative
N/A
5
Westar Energy
Derek Brown
Abstain
N/A
5
Xcel Energy, Inc.
Gerry Huitt
Affirmative
N/A
6
Ameren - Ameren Services
Robert Quinlivan
Negative
N/A
Affirmative
N/A
6
APS - Arizona Public Service
Nicholas Kirby
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Joe Tarantino
8/14/2018
Index - NERC Balloting Tool
Segment
Organization
Page 11 of 13
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
None
N/A
6
Black Hills Corporation
Eric Scherr
None
N/A
6
Bonneville Power
Administration
Andrew Meyers
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Affirmative
N/A
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Affirmative
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Edison International Southern California Edison
Company
Kenya Streeter
None
N/A
6
Exelon
Becky Webb
None
N/A
6
Florida Municipal Power
Agency
Richard
Montgomery
Brandon
McCormick
Negative
N/A
6
Florida Municipal Power Pool
Tom Reedy
Brandon
McCormick
Negative
N/A
6
Great Plains Energy - Kansas
City Power and Light Co.
Jennifer
Flandermeyer
Douglas Webb
Affirmative
N/A
6
Great River Energy
Donna
Stephenson
Michael
Brytowski
Negative
N/A
6
Lincoln Electric System
Eric Ruskamp
Abstain
N/A
6
Los Angeles Department of
Water and Power
Anton Vu
Affirmative
N/A
6
Luminant - Luminant Energy
Brenda Hampton
None
N/A
6
Manitoba Hydro
Blair Mukanik
Abstain
N/A
6
Muscatine Power and Water
Ryan Streck
Negative
N/A
6
New York Power Authority
Thomas Savin
Abstain
N/A
6
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Affirmative
N/A
6
NiSource - Northern Indiana
Public Service Co.
Joe O'Brien
Negative
N/A
Louis Guidry
Shelly Dineen
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Segment
Organization
Page 12 of 13
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Northern California Power
Agency
Dennis Sismaet
Abstain
N/A
6
OGE Energy - Oklahoma Gas
and Electric Co.
Sing Tay
Affirmative
N/A
6
Portland General Electric Co.
Daniel Mason
Affirmative
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Negative
N/A
6
PSEG - PSEG Energy
Resources and Trade LLC
Karla Barton
None
N/A
6
Public Utility District No. 1 of
Chelan County
Davis Jelusich
Abstain
N/A
6
Public Utility District No. 2 of
Grant County, Washington
LeRoy Patterson
Affirmative
N/A
6
Sacramento Municipal Utility
District
Jamie Cutlip
Affirmative
N/A
6
Salt River Project
Bobby Olsen
Affirmative
N/A
6
Santee Cooper
Michael Brown
Affirmative
N/A
6
SCANA - South Carolina
Electric and Gas Co.
John Folsom
None
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Abstain
N/A
6
Snohomish County PUD No. 1
Franklin Lu
Affirmative
N/A
6
Southern Company Southern Company
Generation and Energy
Marketing
Jennifer Sykes
Affirmative
N/A
6
Tacoma Public Utilities
(Tacoma, WA)
Rick Applegate
Affirmative
N/A
6
Tennessee Valley Authority
Marjorie Parsons
Negative
N/A
6
WEC Energy Group, Inc.
David Hathaway
Affirmative
N/A
6
Westar Energy
Grant Wilkerson
Abstain
N/A
Affirmative
N/A
6
Western Area Power
Charles Faust
Administration
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Organization
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Voter
Designated
Proxy
NERC
Memo
Ballot
6
Xcel Energy, Inc.
Carrie Dixon
Affirmative
N/A
7
Luminant Mining Company
LLC
Stewart Rake
None
N/A
8
David Kiguel
David Kiguel
Affirmative
N/A
9
Commonwealth of
Massachusetts Department of
Public Utilities
Donald Nelson
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Negative
N/A
10
New York State Reliability
Council
ALAN ADAMSON
Affirmative
N/A
10
Northeast Power Coordinating
Council
Guy V. Zito
Affirmative
N/A
10
ReliabilityFirst
Anthony
Jablonski
Affirmative
N/A
10
SERC Reliability Corporation
Drew Slabaugh
Affirmative
N/A
10
Texas Reliability Entity, Inc.
Rachel Coyne
Abstain
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
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Exhibit E
Rationale for BAL-002-3
Rationales for BAL-002-3
February, 2018
Requirement R1
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
1.1. within the Contingency Event Recovery Period, demonstrate recovery by returning its
Reporting ACE to at least the recovery value of:
•
zero (if its Pre‐Reporting Contingency Event ACE Value was positive or equal to
zero); however, any Balancing Contingency Event that occurs during the Contingency Event
Recovery Period shall reduce the required recovery: (i) beginning at the time of, and (ii) by
the magnitude of, such individual Balancing Contingency Event,
or,
•
its Pre‐Reporting Contingency Event ACE Value (if its Pre‐Reporting Contingency
Event ACE Value was negative); however, any Balancing Contingency Event that occurs
during the Contingency Event Recovery Period shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, such individual Balancing
Contingency Event.
1.2. document all Reportable Balancing Contingency Events using CR Form 1.
1.3. deploy Contingency Reserve, within system constraints, to respond to all Reportable
Balancing Contingency Events, however, it is not subject to compliance with Requirement R1 part
1.1 if the Responsible Entity:
1.3.1 is (i) a Balancing Authority or (ii) a Reserve Sharing Group with at least one member
that:
•
is a experiencing a Reliability Coordinator declared Energy Emergency Alert
Level, and
•
is utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan, and
•
has depleted its Contingency Reserve to a level below its Most Severe Single
Contingency, and
•
has, during communications with its Reliability Coordinator in accordance
with the Energy Emergency Alert procedures, (i) notified the Reliability Coordinator
of the conditions described in the preceding two bullet points preventing the
Responsible Entity from complying with Requirement R1 part 1.1, and (ii) provided
the Reliability Coordinator with an ACE recovery plan, including target recovery
time.
or,
1.3.2 the Responsible Entity experiences:
•
multiple Contingencies where the combined MW loss exceeds its Most
Severe Single Contingency and that are defined as a single Balancing Contingency
Event, or
•
multiple Balancing Contingency Events within the sum of the time periods
defined by the Contingency Event Recovery Period and Contingency Reserve
Restoration Period whose combined magnitude exceeds the Responsible Entity's
Most Severe Single Contingency.
Rationale R1
Requirement R1 reflects the operating principles first established by NERC Policy 1 (Generation
Control and Performance). Its objective is to assure the Responsible Entity balances resources and
demand and returns its Reporting Area Control Error (ACE) to defined values (subject to applicable
limits) following a Reportable Balancing Contingency Event. It requires the Responsible Entity to
recover from events that would be less than or equal to the Responsible Entity’s MSSC. It
establishes the amount of Contingency Reserve and recovery and restoration timeframes the
Responsible Entity must demonstrate in a compliance evaluation. It is intended to eliminate the
ambiguities and questions associated with the existing standard. In addition, it allows Responsible
Entities to have a clear way to demonstrate compliance and support the Interconnection to the full
extent of its MSSC.
Requirement R1 does not apply when an entity experiences a Balancing Contingency Event that
exceeds its MSSC (which includes multiple Balancing Contingency Events as described in R1 part
1.3.2 below) because a fundamental goal of the SDT is to assure the Responsible Entity has enough
flexibility to maintain service to Demand while managing reliability. The SDT’s intent is to
eliminate any potential overlap or conflict with any other NERC Reliability Standard to eliminate
duplicative reporting, and other issues.
Commenters suggested a Quarterly Compliance similar to the current reports sent to NERC. The
drafting team attempted to draft measurement language and VSL’s for quarterly monitoring of
compliance to R1. But the drafting team found that the VSL levels developed were likely to place
smaller Balancing Authority’s (BA) and Reserve Sharing Groups (RSG) in a severe violation
regardless of the size of the failure. Therefore, the drafting team has not adopted a quarterly
compliance calculation. Also, the proposed requirement and compliance process meets the
directive in Paragraph 354 of Order 693.
The language in R1 part 1.3 does not specifically state under which EEA level the exclusion applies
to reduce the need for consequent modifications of the BAL‐002 standard. Thus, language in
Requirement 1 Part 1.3.1 addresses both current and future EEA process. In addition, the drafting
team has added language to R 1.3.1 clarifying that if a BA is experiencing an EEA event under
BAL‐002‐3 Rationales
February 2018
2
which its contingency reserve has been activated, the RSG in which it resides would also be
considered to be exempt from R1 compliance.
In addition, to address FERC Order No. 835, the drafting team has modified Requirement R1 Part
1.3.1 to clarify that the Responsible Entity, is the Balancing Authority (BA) notifying the Reliability
Coordinator (RC) of the conditions set forth in Requirement R1, Part 1.3.1 in accordance with the
Energy Emergency Alert (EEA) procedures. Under the Energy Emergency Alert procedures, the BA
must inform the RC of the conditions and necessary requirements to meet reliability and the RC
must approve of the information being provided before issuing an Energy Emergency Alert.
Requirement R1 Part 1.3.1 requires the BA to provide additional information to the RC, allowing
the RC to have a wide‐area view of the state of the Bulk Electric System for possible future
decisions concerning the System. It also provides for relief to a BA or RSG when reserves are being
utilized under an EEA. These modifications keep the issues associated with Energy Emergencies
within the Emergency Preparedness and Operations Standards, while allowing BAL‐002‐3 to
compliment the process and clarify the narrow set of conditions where the BA and/or RSG is not
subject to compliance to R1..
Requirement R2
Each Responsible Entity shall develop, review and maintain annually, and implement an Operating Process
as part of its Operating Plan to determine its Most Severe Single Contingency and make preparations to
have Contingency Reserve equal to, or greater than the Responsible Entity’s Most Severe Single
Contingency available for maintaining system reliability.
Rationale R2
R2 establishes the need to actively plan in the near term (e.g., day‐ahead) for expected Reportable
Balancing Contingency Events. This requirement is similar to the current standard which requires
an entity to have available a level of contingency reserves equal to or greater than its Most Severe
Single Contingency.
Requirement R3
Each Responsible Entity, following a Reportable Balancing Contingency Event, shall restore its Contingency
Reserve to at least its Most Severe Single Contingency, before the end of the Contingency Reserve
Restoration Period, but any Balancing Contingency Event that occurs before the end of a Contingency
Reserve Restoration Period resets the beginning of the Contingency Event Recovery Period.
Rationale R3
This requirement is similar to the existing requirement that an entity that has experienced an
event shall restore its Contingency Reserves within 105 minutes of the event. Note that if an entity
is experiencing an EEA it may need to depend on potential availability (or make ready for potential
curtailment) of its firm loads to restore Contingency Reserve. This is the reason for the changes to
the definition of Contingency Reserve in the posting.
BAL‐002‐3 Rationales
February 2018
3
Exhibit F
Standard Drafting Team Roster
Standard Drafting Team Roster
Project 2017-06 Modifications to BAL-002-2
Name
Entity
Chair
Jerry Rust
Northwest Power Pool
Co-Chair
Glenn Stephens
Santee Cooper
Members
Gerry Beckerle
Ameren
Natika Mago
Electric Reliability Council of Texas
Mark Prosperi-Porta
BC Hydro
Lonnie L Lindekugel
Southwest Power Pool
David Kimmel
PJM Interconnection
Sean Erickson
WAPA
Darrel Richardson
North American Electric Reliability Corporation
Robert Cummings
North American Electric Reliability Corporation
Brad Gordon
North American Electric Reliability Corporation
Candice Castaneda
North American Electric Reliability Corporation
NERC Staff
| File Type | application/pdf |
| Author | Marilani Alt |
| File Modified | 2019-02-12 |
| File Created | 2018-08-16 |