Reliability Standard PRC-002-2

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
A. Introduction
1.

Title:

Disturbance Monitoring and Reporting Requirements

2.

Number:

PRC-002-2

3.

Purpose:

To have adequate data available to facilitate analysis of Bulk Electric
System (BES) Disturbances.

4.

Applicability:
Functional Entities:
4.1 The Responsible Entity is:
4.1.1 Eastern Interconnection – Planning Coordinator
4.1.2 ERCOT Interconnection – Planning Coordinator or Reliability Coordinator
4.1.3 Western Interconnection – Reliability Coordinator
4.1.4 Quebec Interconnection – Planning Coordinator or Reliability
Coordinator
4.2 Transmission Owner
4.3 Generator Owner

5.

Effective Dates:
See Implementation Plan

B. Requirements and Measures
R1. Each Transmission Owner shall: [Violation Risk Factor: Lower ] [Time Horizon: Longterm Planning]
1.1. Identify BES buses for which sequence of events recording (SER) and fault
recording (FR) data is required by using the methodology in PRC-002-2,
Attachment 1.
1.2. Notify other owners of BES Elements connected to those BES buses, if any,
within 90-calendar days of completion of Part 1.1, that those BES Elements
require SER data and/or FR data.
1.3. Re-evaluate all BES buses at least once every five calendar years in accordance
with Part 1.1 and notify other owners, if any, in accordance with Part 1.2, and
implement the re-evaluated list of BES buses as per the Implementation Plan.
M1. The Transmission Owner has a dated (electronic or hard copy) list of BES buses for
which SER and FR data is required, identified in accordance with PRC-002-2,
Attachment 1, and evidence that all BES buses have been re-evaluated within the
required intervals under Requirement R1. The Transmission Owner will also have
dated (electronic or hard copy) evidence that it notified other owners in accordance
with Requirement R1.
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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
R2. Each Transmission Owner and Generator Owner shall have SER data for circuit breaker
position (open/close) for each circuit breaker it owns connected directly to the BES
buses identified in Requirement R1 and associated with the BES Elements at those BES
buses. [Violation Risk Factor: Lower ] [Time Horizon: Long-term Planning]
M2. The Transmission Owner or Generator Owner has evidence (electronic or hard copy)
of SER data for circuit breaker position as specified in Requirement R2. Evidence may
include, but is not limited to: (1) documents describing the device interconnections
and configurations which may include a single design standard as representative for
common installations; or (2) actual data recordings; or (3) station drawings.
R3. Each Transmission Owner and Generator Owner shall have FR data to determine the
following electrical quantities for each triggered FR for the BES Elements it owns
connected to the BES buses identified in Requirement R1: [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning]
3.1 Phase-to-neutral voltage for each phase of each specified BES bus.
3.2 Each phase current and the residual or neutral current for the following BES
Elements:
3.2.1 Transformers that have a low-side operating voltage of 100kV or above.
3.2.2 Transmission Lines.
M3. The Transmission Owner or Generator Owner has evidence (electronic or hard copy)
of FR data that is sufficient to determine electrical quantities as specified in
Requirement R3. Evidence may include, but is not limited to: (1) documents describing
the device specifications and configurations which may include a single design
standard as representative for common installations; or (2) actual data recordings or
derivations; or (3) station drawings.
R4. Each Transmission Owner and Generator Owner shall have FR data as specified in
Requirement R3 that meets the following: [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
4.1 A single record or multiple records that include:
• A pre-trigger record length of at least two cycles and a total record length of at
least 30-cycles for the same trigger point, or
• At least two cycles of the pre-trigger data, the first three cycles of the posttrigger data, and the final cycle of the fault as seen by the fault recorder.
4.2 A minimum recording rate of 16 samples per cycle.
4.3 Trigger settings for at least the following:
4.3.1 Neutral (residual) overcurrent.
4.3.2 Phase undervoltage or overcurrent.

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
M4. The Transmission Owner or Generator Owner has evidence (electronic or hard copy)
that FR data meets Requirement R4. Evidence may include, but is not limited to: (1)
documents describing the device specification (R4, Part 4.2) and device configuration
or settings (R4, Parts 4.1 and 4.3), or (2) actual data recordings or derivations.
R5. Each Responsible Entity shall: [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
5.1 Identify BES Elements for which dynamic Disturbance recording (DDR) data is
required, including the following:
5.1.1 Generating resource(s) with:
5.1.1.1 Gross individual nameplate rating greater than or equal to 500
MVA.
5.1.1.2 Gross individual nameplate rating greater than or equal to 300
MVA where the gross plant/facility aggregate nameplate rating is
greater than or equal to 1,000 MVA.
5.1.2 Any one BES Element that is part of a stability (angular or voltage) related
System Operating Limit (SOL).
5.1.3 Each terminal of a high voltage direct current (HVDC) circuit with a
nameplate rating greater than or equal to 300 MVA, on the alternating
current (AC) portion of the converter.
5.1.4 One or more BES Elements that are part of an Interconnection Reliability
Operating Limit (IROL).
5.1.5 Any one BES Element within a major voltage sensitive area as defined by
an area with an in-service undervoltage load shedding (UVLS) program.
5.2 Identify a minimum DDR coverage, inclusive of those BES Elements identified in
Part 5.1, of at least:
5.2.1 One BES Element; and
5.2.2 One BES Element per 3,000 MW of the Responsible Entity’s historical
simultaneous peak System Demand.
5.3 Notify all owners of identified BES Elements, within 90-calendar days of
completion of Part 5.1, that their respective BES Elements require DDR data when
requested.
5.4 Re-evaluate all BES Elements at least once every five calendar years in accordance
with Parts 5.1 and 5.2, and notify owners in accordance with Part 5.3 to implement
the re-evaluated list of BES Elements as per the Implementation Plan.
M5. The Responsible Entity has a dated (electronic or hard copy) list of BES Elements for
which DDR data is required, developed in accordance with Requirement R5, Part 5.1
and Part 5.2; and re-evaluated in accordance with Part 5.4. The Responsible Entity has
dated evidence (electronic or hard copy) that each Transmission Owner or Generator
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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
Owner has been notified in accordance with Requirement 5, Part 5.3. Evidence may
include, but is not limited to: letters, emails, electronic files, or hard copy records
demonstrating transmittal of information.
R6. Each Transmission Owner shall have DDR data to determine the following electrical
quantities for each BES Element it owns for which it received notification as identified
in Requirement R5: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning ]
6.1 One phase-to-neutral or positive sequence voltage.
6.2 The phase current for the same phase at the same voltage corresponding to the
voltage in Requirement R6, Part 6.1, or the positive sequence current.
6.3 Real Power and Reactive Power flows expressed on a three phase basis
corresponding to all circuits where current measurements are required.
6.4 Frequency of any one of the voltage(s) in Requirement R6, Part 6.1.
M6. The Transmission Owner has evidence (electronic or hard copy) of DDR data to
determine electrical quantities as specified in Requirement R6. Evidence may include,
but is not limited to: (1) documents describing the device specifications and
configurations, which may include a single design standard as representative for
common installations; or (2) actual data recordings or derivations; or (3) station
drawings.
R7. Each Generator Owner shall have DDR data to determine the following electrical
quantities for each BES Element it owns for which it received notification as identified
in Requirement R5: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
7.1 One phase-to-neutral, phase-to-phase, or positive sequence voltage at either the
generator step-up transformer (GSU) high-side or low-side voltage level.
7.2 The phase current for the same phase at the same voltage corresponding to the
voltage in Requirement R7, Part 7.1, phase current(s) for any phase-to-phase
voltages, or positive sequence current.
7.3 Real Power and Reactive Power flows expressed on a three phase basis
corresponding to all circuits where current measurements are required.
7.4 Frequency of at least one of the voltages in Requirement R7, Part 7.1.
M7. The Generator Owner has evidence (electronic or hard copy) of DDR data to
determine electrical quantities as specified in Requirement R7. Evidence may include,
but is not limited to: (1) documents describing the device specifications and
configurations, which may include a single design standard as representative for
common installations; or (2) actual data recordings or derivations; or (3) station
drawings.
R8. Each Transmission Owner and Generator Owner responsible for DDR data for the BES
Elements identified in Requirement R5 shall have continuous data recording and
storage. If the equipment was installed prior to the effective date of this standard and

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
is not capable of continuous recording, triggered records must meet the following:
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
8.1 Triggered record lengths of at least three minutes.
8.2 At least one of the following three triggers:
 Off nominal frequency trigger set at:
o
o
o
o

Eastern Interconnection
Western Interconnection
ERCOT Interconnection
Hydro-Quebec
Interconnection

Low

High

<59.75 Hz
<59.55 Hz
<59.35 Hz

>61.0 Hz
>61.0 Hz
>61.0 Hz

<58.55 Hz

>61.5 Hz

 Rate of change of frequency trigger set at:
o
o
o
o

Eastern Interconnection
Western Interconnection
ERCOT Interconnection
Hydro-Quebec
Interconnection

< -0.03125 Hz/sec
< -0.05625 Hz/sec
< -0.08125 Hz/sec

> 0.125 Hz/sec
> 0.125 Hz/sec
> 0.125 Hz/sec

< -0.18125 Hz/sec

> 0.1875 Hz/sec

 Undervoltage trigger set no lower than 85 percent of normal operating voltage
for a duration of 5 seconds.
M8. Each Transmission Owner and Generator Owner has dated evidence (electronic or
hard copy) of data recordings and storage in accordance with Requirement R8.
Evidence may include, but is not limited to: (1) documents describing the device
specifications and configurations, which may include a single design standard as
representative for common installations; or (2) actual data recordings.
R9. Each Transmission Owner and Generator Owner responsible for DDR data for the BES
Elements identified in Requirement R5 shall have DDR data that meet the following:
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
9.1 Input sampling rate of at least 960 samples per second.
9.2 Output recording rate of electrical quantities of at least 30 times per second.
M9. The Transmission Owner or Generator Owner has evidence (electronic or hard copy)
that DDR data meets Requirement R9. Evidence may include, but is not limited to: (1)
documents describing the device specification, device configuration, or settings (R9,
Part 9.1; R9, Part 9.2); or (2) actual data recordings (R9, Part 9.2).

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
R10. Each Transmission Owner and Generator Owner shall time synchronize all SER and FR
data for the BES buses identified in Requirement R1 and DDR data for the BES
Elements identified in Requirement R5 to meet the following: [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning]
10.1 Synchronization to Coordinated Universal Time (UTC) with or without a local time
offset.
10.2 Synchronized device clock accuracy within ± 2 milliseconds of UTC.
M10. The Transmission Owner or Generator Owner has evidence (electronic or hard copy)
of time synchronization described in Requirement R10. Evidence may include, but is
not limited to: (1) documents describing the device specification, configuration, or
setting; (2) time synchronization indication or status; or 3) station drawings.
R11. Each Transmission Owner and Generator Owner shall provide, upon request, all SER
and FR data for the BES buses identified in Requirement R1 and DDR data for the BES
Elements identified in Requirement R5 to the Responsible Entity, Regional Entity, or
NERC in accordance with the following: [Violation Risk Factor: Lower] [Time Horizon:
Long-term Planning]
11.1 Data will be retrievable for the period of 10-calendar days, inclusive of the day
the data was recorded.
11.2 Data subject to Part 11.1 will be provided within 30-calendar days of a request
unless an extension is granted by the requestor.
11.3 SER data will be provided in ASCII Comma Separated Value (CSV) format
following Attachment 2.
11.4 FR and DDR data will be provided in electronic files that are formatted in
conformance with C37.111, (IEEE Standard for Common Format for Transient
Data Exchange (COMTRADE), revision C37.111-1999 or later.
11.5 Data files will be named in conformance with C37.232, IEEE Standard for
Common Format for Naming Time Sequence Data Files (COMNAME), revision
C37.232-2011 or later.
M11. The Transmission Owner or Generator Owner has evidence (electronic or hard copy)
that data was submitted upon request in accordance with Requirement R11.
Evidence may include, but is not limited to: (1) dated transmittals to the requesting
entity with formatted records; (2) documents describing data storage capability,
device specification, configuration or settings; or (3) actual data recordings.
R12. Each Transmission Owner and Generator Owner shall, within 90-calendar days of the
discovery of a failure of the recording capability for the SER, FR or DDR data, either:
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]



Restore the recording capability, or
Submit a Corrective Action Plan (CAP) to the Regional Entity and implement it.

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements

M12. The Transmission Owner or Generator Owner has dated evidence (electronic or hard
copy) that meets Requirement R12. Evidence may include, but is not limited to: (1)
dated reports of discovery of a failure, (2) documentation noting the date the data
recording was restored, (3) SCADA records, or (4) dated CAP transmittals to the
Regional Entity and evidence that it implemented the CAP.
C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods 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 Transmission Owner, Generator Owner, Planning Coordinator, and Reliability
Coordinator shall keep data or evidence to show compliance as identified below
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
The Transmission Owner shall retain evidence of Requirement R1, Measure M1 for
five calendar years.
The Transmission Owner shall retain evidence of Requirement R6, Measure M6 for
three calendar years.
The Generator Owner shall retain evidence of Requirement R7, Measure M7 for
three calendar years.
The Transmission Owner and Generator Owner shall retain evidence of requested
data provided as per Requirements R2, R3, R4, R8, R9, R10, R11, and R12,
Measures M2, M3, M4, M8, M9, M10, M11, and M12 for three calendar years.
The Responsible Entity (Planning Coordinator or Reliability Coordinator, as
applicable) shall retain evidence of Requirement R5, Measure M5 for five calendar
years.

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
If a Transmission Owner, Generator Owner, or Responsible Entity is found noncompliant, it shall keep information related to the non-compliance until mitigation is
completed and approved or for the time specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaints
1.4. Additional Compliance Information
None

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
Table of Compliance Elements
R#

R1

Time
Horizon
Long-term
Planning

VRF

Lower

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

The Transmission
Owner identified the
BES buses as directed
by Requirement R1,
Part 1.1 or Part 1.3 for
more than 80 percent
but less than 100
percent of the
required BES buses
that they own.

The Transmission
Owner identified the
BES buses as directed
by Requirement R1,
Part 1.1 or Part 1.3 for
more than 70 percent
but less than or equal
to 80 percent of the
required BES buses
that they own.

The Transmission
Owner identified the
BES buses as directed
by Requirement R1,
Part 1.1 or Part 1.3 for
more than 60 percent
but less than or equal
to 70 percent of the
required BES buses
that they own.

The Transmission
Owner identified the
BES buses as directed
by Requirement R1,
Part 1.1 or Part 1.3 for
less than or equal to
60 percent of the
required BES buses
that they own.

OR

OR

OR

The Transmission
Owner evaluated the
BES buses as directed
by Requirement R1,
Part 1.1 or Part 1.3 but
was late by 30calendar days or less.

The Transmission
Owner evaluated the
BES buses as directed
by Requirement R1,
Part 1.1 or Part 1.3 but
was late by greater
than 30-calendar days
and less than or equal
to 60-calendar days.

The Transmission
Owner evaluated the
BES buses as directed
by Requirement R1,
Part 1.1 or Part 1.3 but
was late by greater
than 60-calendar days
and less than or equal
to 90-calendar days.

The Transmission
Owner evaluated the
BES buses as directed
by Requirement R1,
Part 1.1 or Part 1.3 but
was late by greater
than 90-calendar days.

OR

OR

The Transmission
Owner as directed by
Requirement R1, Part

The Transmission
Owner as directed by
Requirement R1, Part

OR
The Transmission
Owner as directed by
Requirement R1, Part
1.2 was late in
notifying the other

Page 9 of 38

OR

OR
The Transmission
Owner as directed by
Requirement R1, Part
1.2 was late in
notifying one or more
other owners by

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
owners by 10-calendar
days or less.

1.2 was late in
notifying the other
owners by greater
than 10-calendar days
but less than or equal
to 20-calendar days.

1.2 was late in
notifying the other
owners by greater
than 20-calendar days
but less than or equal
to 30-calendar days.

greater than 30calendar days.

R2

Long-term
Planning

Lower

Each Transmission
Owner or Generator
Owner as directed by
Requirement R2 had
more than 80 percent
but less than 100
percent of the total
SER data for circuit
breaker position
(open/close) for each
of the circuit breakers
at the BES buses
identified in
Requirement R1.

Each Transmission
Owner or Generator
Owner as directed by
Requirement R2 had
more than 70 percent
but less than or equal
to 80 percent of the
total SER data for
circuit breaker position
(open/close) for each
of the circuit breakers
at the BES buses
identified in
Requirement R1.

Each Transmission
Owner or Generator
Owner as directed by
Requirement R2 had
more than 60 percent
but less than or equal
to 70 percent of the
total SER data for
circuit breaker position
(open/close) for each
of the circuit breakers
at the BES buses
identified in
Requirement R1.

Each Transmission
Owner or Generator
Owner as directed by
Requirement R2 for
less than or equal to
60 percent of the total
SER data for circuit
breaker position
(open/close) for each
of the circuit breakers
at the BES buses
identified in
Requirement R1.

R3

Long-term
Planning

Lower

The Transmission
Owner or Generator
Owner had FR data as
directed by
Requirement R3, Parts
3.1 and 3.2 that covers
more than 80 percent
but less than 100
percent of the total set
of required electrical

The Transmission
Owner or Generator
Owner had FR data as
directed by
Requirement R3, Parts
3.1 and 3.2 that covers
more than 70 percent
but less than or equal
to 80 percent of the
total set of required

The Transmission
Owner or Generator
Owner had FR data as
directed by
Requirement R3, Parts
3.1 and 3.2 that covers
more than 60 percent
but less than or equal
to 70 percent of the
total set of required

The Transmission
Owner or Generator
Owner had FR data as
directed by
Requirement R3, Parts
3.1 and 3.2 that covers
less than or equal to
60 percent of the total
set of required
electrical quantities,

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
quantities, which is the
product of the total
number of monitored
BES Elements and the
number of specified
electrical quantities for
each BES Element.

electrical quantities,
which is the product of
the total number of
monitored BES
Elements and the
number of specified
electrical quantities for
each BES Element.

electrical quantities,
which is the product of
the total number of
monitored BES
Elements and the
number of specified
electrical quantities for
each BES Element.

which is the product of
the total number of
monitored BES
Elements and the
number of specified
electrical quantities for
each BES Element.

R4

Long-term
Planning

Lower

The Transmission
Owner or Generator
Owner had FR data
that meets more than
80 percent but less
than 100 percent of
the total recording
properties as specified
in Requirement R4.

The Transmission
Owner or Generator
Owner had FR data
that meets more than
70 percent but less
than or equal to 80
percent of the total
recording properties
as specified in
Requirement R4.

The Transmission
Owner or Generator
Owner had FR data
that meets more than
60 percent but less
than or equal to 70
percent of the total
recording properties
as specified in
Requirement R4.

The Transmission
Owner or Generator
Owner had FR data
that meets less than or
equal to 60 percent of
the total recording
properties as specified
in Requirement R4.

R5

Long-term
Planning

Lower

The Responsible Entity
identified the BES
Elements for which
DDR data is required
as directed by
Requirement R5 for
more than 80 percent
but less than 100
percent of the
required BES Elements
included in Part 5.1.

The Responsible Entity
identified the BES
Elements for which
DDR data is required
as directed by
Requirement R5 for
more than 70 percent
but less than or equal
to 80 percent of the
required BES Elements
included in Part 5.1.

The Responsible Entity
identified the BES
Elements for which
DDR data is required
as directed by
Requirement R5 for
more than 60 percent
but less than or equal
to 70 percent of the
required BES Elements
included in Part 5.1.

The Responsible Entity
identified the BES
Elements for which
DDR data is required
as directed by
Requirement R5 for
less than or equal to
60 percent of the
required BES Elements
included in Part 5.1.

Page 11 of 38

OR

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
OR

OR

OR

The Responsible Entity
identified the BES
Elements for DDR as
directed by
Requirement R5, Part
5.1 or Part 5.4 but was
late by 30-calendar
days or less.

The Responsible Entity
identified the BES
Elements for DDR as
directed by
Requirement R5, Part
5.1 or Part 5.4 but was
late by greater than
30-calendar days and
less than or equal to
60 -calendar days.

The Responsible Entity
identified the BES
Elements for DDR as
directed by
Requirement R5, Part
5.1 or Part 5.4 but was
late by greater than
60-calendar days and
less than or equal to
90-calendar days.

OR

OR

The Responsible Entity
as directed by
Requirement R5, Part
5.3 was late in
notifying the owners
by greater than 10calendar days but less
than or equal to 20calendar days.

The Responsible Entity
as directed by
Requirement R5, Part
5.3 was late in
notifying the owners
by greater than 20calendar days but less
than or equal to 30calendar days.

The Transmission
Owner had DDR data
as directed by
Requirement R6, Parts
6.1 through 6.4 for
more than 70 percent
but less than or equal
to 80 percent of the

The Transmission
Owner had DDR data
as directed by
Requirement R6, Parts
6.1 through 6.4 for
more than 60 percent
but less than or equal
to 70 percent of the

OR
The Responsible Entity
as directed by
Requirement R5, Part
5.3 was late in
notifying the owners
by 10-calendar days or
less.

R6

Long-term
Planning

Lower

The Transmission
Owner had DDR data
as directed by
Requirement R6, Parts
6.1 through 6.4 that
covered more than 80
percent but less than
100 percent of the

Page 12 of 38

The Responsible Entity
identified the BES
Elements for DDR as
directed by
Requirement R5, Part
5.1 or Part 5.4 but was
late by greater than
90-calendar days.
OR
The Responsible Entity
as directed by
Requirement R5, Part
5.3 was late in
notifying one or more
owners by greater
than 30-calendar days.
OR
The Responsible Entity
failed to ensure a
minimum DDR
coverage per Part 5.2.
The Transmission
Owner failed to have
DDR data as directed
by Requirement R6,
Parts 6.1 through 6.4.

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
total required
electrical quantities for
all applicable BES
Elements.

total required
electrical quantities for
all applicable BES
Elements.

total required
electrical quantities for
all applicable BES
Elements.

R7

Long-term
Planning

Lower

The Generator Owner
had DDR data as
directed by
Requirement R7, Parts
7.1 through 7.4 that
covers more than 80
percent but less than
100 percent of the
total required
electrical quantities for
all applicable BES
Elements.

The Generator Owner
had DDR data as
directed by
Requirement R7, Parts
7.1 through 7.4 for
more than 70 percent
but less than or equal
to 80 percent of the
total required
electrical quantities for
all applicable BES
Elements.

The Generator Owner
had DDR data as
directed by
Requirement R7, Parts
7.1 through 7.4 for
more than 60 percent
but less than or equal
to 70 percent of the
total required
electrical quantities for
all applicable BES
Elements.

The Generator Owner
failed to have DDR
data as directed by
Requirement R7, Parts
7.1 through 7.4.

R8

Long-term
Planning

Lower

The Transmission
Owner or Generator
Owner had continuous
or non-continuous
DDR data, as directed
in Requirement R8, for
more than 80 percent
but less than 100
percent of the BES
Elements they own as
determined in
Requirement R5.

The Transmission
Owner or Generator
Owner had continuous
or non-continuous
DDR data, as directed
in Requirement R8, for
more than 70 percent
but less than or equal
to 80 percent of the
BES Elements they
own as determined in
Requirement R5.

The Transmission
Owner or Generator
Owner had continuous
or non-continuous
DDR data, as directed
in Requirement R8, for
more than 60 percent
but less than or equal
to 70 percent of the
BES Elements they
own as determined in
Requirement R5.

The Transmission
Owner or Generator
Owner failed to have
continuous or noncontinuous DDR data,
as directed in
Requirement R8, for
the BES Elements they
own as determined in
Requirement R5.

Page 13 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements

R9

Long-term
Planning

Lower

The Transmission
Owner or Generator
Owner had DDR data
that meets more than
80 percent but less
than 100 percent of
the total recording
properties as specified
in Requirement R9.

The Transmission
Owner or Generator
Owner had DDR data
that meets more than
70 percent but less
than or equal to 80
percent of the total
recording properties
as specified in
Requirement R9.

The Transmission
Owner or Generator
Owner had DDR data
that meets more than
60 percent but less
than or equal to 70
percent of the total
recording properties
as specified in
Requirement R9.

The Transmission
Owner or Generator
Owner had DDR data
that meets less than or
equal to 60 percent of
the total recording
properties as specified
in Requirement R9.

R10 Long-term
Planning

Lower

The Transmission
Owner or Generator
Owner had time
synchronization per
Requirement R10,
Parts 10.1 and 10.2 for
SER, FR, and DDR data
for more than 90
percent but less than
100 percent of the BES
buses identified in
Requirement R1 and
BES Elements
identified in
Requirement R5 as
directed by
Requirement R10.

The Transmission
Owner or Generator
Owner had time
synchronization per
Requirement R10,
Parts 10.1 and 10.2 for
SER, FR, and DDR data
for more than 80
percent but less than
or equal to 90 percent
of the BES buses
identified in
Requirement R1 and
BES Elements
identified in
Requirement R5 as
directed by
Requirement R10.

The Transmission
Owner or Generator
Owner had time
synchronization per
Requirement R10,
Parts 10.1 and 10.2 for
SER, FR, and DDR data
for more than 70
percent but less than
or equal to 80 percent
of the BES buses
identified in
Requirement R1 and
BES Elements
identified in
Requirement R5 as
directed by
Requirement R10.

The Transmission
Owner or Generator
Owner failed to have
time synchronization
per Requirement R10,
Parts 10.1 and 10.2
for SER, FR, and DDR
data for less than or
equal to 70 percent of
the BES buses
identified in
Requirement R1 and
BES Elements
identified in
Requirement R5 as
directed by
Requirement R10.

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements

R11 Long-term
Planning

Lower

The Transmission
Owner or Generator
Owner as directed by
Requirement R11, Part
11.1 provided the
requested data more
than 30-calendar days
but less than 40calendar days after the
request unless an
extension was granted
by the requesting
authority.

The Transmission
Owner or Generator
Owner as directed by
Requirement R11, Part
11.1 provided the
requested data more
than 40-calendar days
but less than or equal
to 50-calendar days
after the request
unless an extension
was granted by the
requesting authority.

The Transmission
Owner or Generator
Owner as directed by
Requirement R11, Part
11.1 provided the
requested data more
than 50-calendar days
but less than or equal
to 60-calendar days
after the request
unless an extension
was granted by the
requesting authority.

OR

OR

OR

The Transmission
Owner or Generator
Owner as directed by
Requirement R11, Part
11.1 failed to provide
the requested data
more than 60-calendar
days after the request
unless an extension
was granted by the
requesting authority.
OR

The Transmission
Owner or Generator
The Transmission
The Transmission
The Transmission
Owner as directed by
Owner or Generator
Owner or Generator
Owner or Generator
Requirement R11
Owner as directed by
Owner as directed by
Owner as directed by
failed to provide less
Requirement R11
Requirement R11
Requirement R11
than or equal to 70
provided more than 90 provided more than 80 provided more than 70 percent of the
percent but less than
percent but less than
percent but less than
requested data.
100 percent of the
or equal to 90 percent or equal to 80 percent OR
requested data.
of the requested data. of the requested data.
The Transmission
OR
OR
OR
Owner or Generator
The Transmission
The Transmission
The Transmission
Owner as directed by
Owner or Generator
Owner or Generator
Owner or Generator
Requirement R11,
Owner as directed by
Owner as directed by
Owner as directed by
Parts 11.3 through
Requirement R11,
Requirement R11,
Requirement R11,
11.5 provided less
Parts 11.3 through
Parts 11.3 through
Parts 11.3 through
than or equal to 70
11.5 provided more
11.5 provided more
11.5 provided more
percent of the data in

Page 15 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements

R12 Long-term
Planning

Lower

than 90 percent of the
data but less than 100
percent of the data in
the proper data
format.

than 80 percent of the
data but less than or
equal to 90 percent of
the data in the proper
data format.

than 70 percent of the
data but less than or
equal to 80 percent of
the data in the proper
data format.

the proper data
format.

The Transmission
Owner or Generator
Owner as directed by
Requirement R12
reported a failure and
provided a Corrective
Action Plan to the
Regional Entity more
than 90-calendar days
but less than or equal
to 100-calendar days
after discovery of the
failure.

The Transmission
Owner or Generator
Owner as directed by
Requirement R12
reported a failure and
provided a Corrective
Action Plan to the
Regional Entity more
than 100-calendar
days but less than or
equal to 110-calendar
days after discovery of
the failure.

The Transmission
Owner or Generator
Owner as directed by
Requirement R12
reported a failure and
provided a Corrective
Action Plan to the
Regional Entity more
than 110-calendar
days but less than or
equal to 120-calendar
days after discovery of
the failure.

The Transmission
Owner or Generator
Owner as directed by
Requirement R12
failed to report a
failure and provide a
Corrective Action Plan
to the Regional Entity
more than 120calendar days after
discovery of the
failure.

OR

Transmission Owner or
Generator Owner as
directed by
Requirement R12
failed to restore the
recording capability
and failed to submit a
CAP to the Regional
Entity.

The Transmission
Owner or Generator
Owner as directed by
Requirement R12
submitted a CAP to the
Regional Entity but
failed to implement it.

Page 16 of 38

OR

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.
G. References
IEEE C37.111: Common format for transient data exchange (COMTRADE) for power
Systems.
IEEE C37.232-2011, IEEE Standard for Common Format for Naming Time Sequence Data
Files (COMNAME). Standard published 11/09/2011 by IEEE.
NPCC SP6 Report Synchronized Event Data Reporting, revised March 31, 2005
U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout
in the United States and Canada: Causes and Recommendations (2004).
U.S.-Canada Power System Outage Task Force Interim Report: Causes of the August 14th
Blackout in the United States and Canada (Nov. 2003)
Version History
Version

Date

Action

Change Tracking

0

February 8,
2005

Adopted by NERC Board of Trustees

New

1

August 2, 2006

Adopted by NERC Board of Trustees

Revised

2

November 13,
2014

Adopted by NERC Board of Trustees

Revised under
Project 2007-11
and merged with
PRC-018-1.

Page 17 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements

Attachment 1
Methodology for Selecting Buses for Capturing Sequence of Events Recording (SER) and Fault
Recording (FR) Data
(Requirement R1)
To identify monitored BES buses for sequence of events recording (SER) and Fault recording
(FR) data required by Requirement 1, each Transmission Owner shall follow sequentially, unless
otherwise noted, the steps listed below:
Step 1.

Determine a complete list of BES buses that it owns.
For the purposes of this standard, a single BES bus includes physical buses with
breakers connected at the same voltage level within the same physical location
sharing a common ground grid. These buses may be modeled or represented by
a single node in fault studies. For example, ring bus or breaker-and-a-half bus
configurations are considered to be a single bus.

Step 2.

Reduce the list to those BES buses that have a maximum available calculated
three phase short circuit MVA of 1,500 MVA or greater. If there are no buses on
the resulting list, proceed to Step 7.

Step 3.

Determine the 11 BES buses on the list with the highest maximum available
calculated three phase short circuit MVA level. If the list has 11 or fewer buses,
proceed to Step 7.

Step 4.

Calculate the median MVA level of the 11 BES buses determined in Step 3.

Step 5.

Multiply the median MVA level determined in Step 4 by 20 percent.

Step 6.

Reduce the BES buses on the list to only those that have a maximum available
calculated three phase short circuit MVA higher than the greater of:

Step 7.

●

1,500 MVA or

●

20 percent of median MVA level determined in Step 5.

If there are no BES buses on the list: the procedure is complete and no FR and
SER data will be required. Proceed to Step 9.
If the list has 1 or more but less than or equal to 11 BES buses: FR and SER data is
required at the BES bus with the highest maximum available calculated three
phase short circuit MVA as determined in Step 3. Proceed to Step 9.

Page 18 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
If the list has more than 11 BES buses: SER and FR data is required on at least the
10 percent of the BES buses determined in Step 6 with the highest maximum
available calculated three phase short circuit MVA. Proceed to Step 8.
Step 8.

SER and FR data is required at additional BES buses on the list determined in
Step 6. The aggregate of the number of BES buses determined in Step 7 and this
Step will be at least 20 percent of the BES buses determined in Step 6.
The additional BES buses are selected, at the Transmission Owner’s discretion, to
provide maximum wide-area coverage for SER and FR data. The following BES
bus locations are recommended:







Step 9.

Electrically distant buses or electrically distant from other DME devices.
Voltage sensitive areas.
Cohesive load and generation zones.
BES buses with a relatively high number of incident Transmission circuits.
BES buses with reactive power devices.
Major Facilities interconnecting outside the Transmission Owner’s area.

The list of monitored BES buses for SER and FR data for Requirement R1 is the
aggregate of the BES buses determined in Steps 7 and 8.

Page 19 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements

Attachment 2
Sequence of Events Recording (SER) Data Format
(Requirement R11, Part 11.3)
Date, Time, Local Time Code, Substation, Device, State1
08/27/13, 23:58:57.110, -5, Sub 1, Breaker 1, Close
08/27/13, 23:58:57.082, -5, Sub 2, Breaker 2, Close
08/27/13, 23:58:47.217, -5, Sub 1, Breaker 1, Open
08/27/13, 23:58:47.214, -5, Sub 2, Breaker 2, Open

1

“OPEN” and “CLOSE” are used as examples. Other terminology such as TRIP, TRIP TO LOCKOUT, RECLOSE, etc. is
also acceptable.

Page 20 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements

High Level Requirement Overview

Requireme
nt

Entity

Identify
BES
Buses

Notification

SER

FR

5 Year
Reevaluatio
n

R1

TO

X

X

X

X

X

R2

TO | GO

R3

TO | GO

X

R4

TO | GO

X

X

Identify
BES
Element
s

Requireme
nt

Entity

Notification

DDR

5 Year Reevaluation

R5

RE (PC | RC)

X

X

X

R6

TO

X

R7

GO

X

R8

TO | GO

X

R9

TO | GO

X

X

Requireme
nt

Entity

Time
Synchronizati
on

R10

TO | GO

X

R11

TO | GO

R12

TO | GO

Provide SER, FR,
DDR Data

SER, FR, DDR
Availability

X
X

Page 21 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
Rationale:

During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon BOT approval, the text from the rationale
text boxes was moved to this section.
Rationale for Functional Entities:
When the term “Responsible Entity” is used in PRC-002-2, it specifically refers to those entities
listed under 4.1. The Responsible Entity – the Planning Coordinator or Reliability Coordinator, as
applicable in each Interconnection – has the best wide-area view of the BES and is most suited
to be responsible for determining the BES Elements for which dynamic Disturbance recording
(DDR) data is required. The Transmission Owners and Generator Owners will have the
responsibility for ensuring that adequate data is available for those BES Elements selected.
BES buses where sequence of events recording (SER) and fault recording (FR) data is required
are best selected by Transmission Owners because they have the required tools, information,
and working knowledge of their Systems to determine those buses. The Transmission Owners
and Generator Owners that own BES Elements on those BES buses will have the responsibility
for ensuring that adequate data is available.
Rationale for R1:
Analysis and reconstruction of BES events requires SER and FR data from key BES buses.
Attachment 1 provides a uniform methodology to identify those BES buses. Repeated testing of
the Attachment 1 methodology has demonstrated the proper distribution of SER and FR data
collection. Review of actual BES short circuit data received from the industry in response to the
DMSDT’s data request (June 5, 2013 through July 5, 2013) illuminated a strong correlation
between the available short circuit MVA at a Transmission bus and its relative size and
importance to the BES based on (i) its voltage level, (ii) the number of Transmission Lines and
other BES Elements connected to the BES bus, and (iii) the number and size of generating units
connected to the bus. BES buses with a large short circuit MVA level are BES Elements that have
a significant effect on System reliability and performance. Conversely, BES buses with very low
short circuit MVA levels seldom cause wide-area or cascading System events, so SER and FR
data from those BES Elements are not as significant. After analyzing and reviewing the collected
data submittals from across the continent, the threshold MVA values were chosen to provide
sufficient data for event analysis using engineering and operational judgment.
Concerns have existed that the defined methodology for bus selection will overly concentrate
data to selected BES buses. For the purpose of PRC-002-2, there are a minimum number of BES
buses for which SER and FR data is required based on the short circuit level. With these
concepts and the objective being sufficient recording coverage for event analysis, the DMSDT
developed the procedure in Attachment 1 that utilizes the maximum available calculated three
phase short circuit MVA. This methodology ensures comparable and sufficient coverage for SER
and FR data regardless of variations in the size and System topology of Transmission Owners
across all Interconnections. Additionally, this methodology provides a degree of flexibility for
the use of judgment in the selection process to ensure sufficient distribution.

Page 22 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
BES buses where SER and FR data is required are best selected by Transmission Owners
because they have the required tools, information, and working knowledge of their Systems to
determine those buses.
Each Transmission Owner must re-evaluate the list of BES buses at least every five calendar
years to address System changes since the previous evaluation. Changes to the BES do not
mandate immediate inclusion of BES buses into the currently enforced list, but the list of BES
buses will be re-evaluated at least every five calendar years to address System changes since
the previous evaluation.
Since there may be multiple owners of equipment that comprise a BES bus, the notification
required in R1 is necessary to ensure all owners are notified.
A 90-calendar day notification deadline provides adequate time for the Transmission Owner to
make the appropriate determination and notification.
Rationale for R2:
The intent is to capture SER data for the status (open/close) of the circuit breakers that can
interrupt the current flow through each BES Element connected to a BES bus. Change of state
of circuit breaker position, time stamped according to Requirement R10 to a time synchronized
clock, provides the basis for assembling the detailed sequence of events timeline of a power
System Disturbance. Other status monitoring nomenclature can be used for devices other than
circuit breakers.
Rationale for R3:
The required electrical quantities may either be directly measured or determinable if sufficient
FR data is captured (e.g. residual or neutral current if the phase currents are directly
measured). In order to cover all possible fault types, all BES bus phase-to-neutral voltages are
required to be determinable for each BES bus identified in Requirement R1. BES bus voltage
data is adequate for System Disturbance analysis. Phase current and residual current are
required to distinguish between phase faults and ground faults. It also facilitates determination
of the fault location and cause of relay operation. For transformers (Part 3.2.1), the data may
be from either the high-side or the low-side of the transformer. Generator step-up
transformers (GSUs) and leads that connect the GSU transformer(s) to the Transmission System
that are used exclusively to export energy directly from a BES generating unit or generating
plant are excluded from Requirement R3 because the fault current contribution from a
generator to a fault on the Transmission System will be captured by FR data on the
Transmission System, and Transmission System FR will capture faults on the generator
interconnection.
Generator Owners may install this capability or, where the Transmission Owners already have
suitable FR data, contract with the Transmission Owner. However, when required, the
Generator Owner is still responsible for the provision of this data.

Page 23 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
Rationale for R4:
Time stamped pre- and post-trigger fault data aid in the analysis of power System operations
and determination if operations were as intended. System faults generally persist for a short
time period, thus a 30-cycle total minimum record length is adequate. Multiple records allow
for legacy microprocessor relays which, when time-synchronized, are capable of providing
adequate fault data but not capable of providing fault data in a single record with 30contiguous cycles total.
A minimum recording rate of 16 samples per cycle (960 Hz) is required to get sufficient point on
wave data for recreating accurate fault conditions.
Rationale for R5:
DDR is used for capturing the BES transient and post-transient response following Disturbances,
and the data is used for event analysis and validating System performance. DDR plays a critical
role in wide-area Disturbance analysis, and Requirement R5 ensures there is adequate widearea coverage of DDR data for specific BES Elements to facilitate accurate and efficient event
analysis. The Responsible Entity has the best wide-area view of the System and needs to
ensure that there are sufficient BES Elements identified for DDR data capture. The
identification of BES Elements requiring DDR data as per Requirement R5 is based upon
industry experience with wide-area Disturbance analysis and the need for adequate data to
facilitate event analysis. Ensuring data is captured for these BES Elements will significantly
improve the accuracy of analysis and understanding of why an event occurred, not simply what
occurred.
From its experience with changes to the Bulk Electric System that would affect DDR, the DMSDT
decided that the five calendar year re-evaluation of the list is a reasonable interval for this
review. Changes to the BES do not mandate immediate inclusion of BES Elements into the in
force list, but the list of BES Elements will be re-evaluated at least every five calendar years to
address System changes since the previous evaluation. However, this standard does not
preclude the Responsible Entity from performing this re-evaluation more frequently to capture
updated BES Elements.
The Responsible Entity, for the purposes of this standard, is defined as the PC or RC depending
upon Interconnection, because they have the best overall perspective for determining widearea DDR coverage. The Planning Coordinator and Reliability Coordinator assume different
functions across the continent; therefore the Responsible Entity is defined in the Applicability
Section and used throughout this standard.
The Responsible Entity must notify all owners of the selected BES Elements that DDR data is
required for this standard. The Responsible Entity is only required to share the list of selected
BES Elements that each Transmission Owner and Generator Owner respectively owns, not the
entire list. This communication of selected BES Elements is required to ensure that the owners
of the respective BES Elements are aware of their responsibilities under this standard.
Implementation of the monitoring equipment is the responsibility of the respective
Transmission Owners and Generator Owners, the timeline for installing this capability is
Page 24 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
outlined in the Implementation Plan, and starts from notification of the list from the
Responsible Entity. Data for each BES Element as defined by the Responsible Entity must be
provided; however, this data can be either directly measured or accurately calculated. With the
exception of HVDC circuits, DDR data is only required for one end or terminal of the BES
Elements selected. For example, DDR data must be provided for at least one terminal of a
Transmission Line or generator step-up (GSU) transformer, but not both terminals. For an
interconnection between two Responsible Entities, each Responsible Entity will consider this
interconnection independently, and are expected to work cooperatively to determine how to
monitor the BES Elements that require DDR data. For an interconnection between two TO’s, or
a TO and a GO, the Responsible Entity will determine which entity will provide the data. The
Responsible Entity will notify the owners that their BES Elements require DDR data.
Refer to the Guidelines and Technical Basis Section for more detail on the rationale and
technical reasoning for each identified BES Element in Requirement R5, Part 5.1; monitoring
these BES Elements with DDR will facilitate thorough and informative event analysis of widearea Disturbances on the BES. Part 5.2 is included to ensure wide-area coverage across all
Responsible Entities. It is intended that each Responsible Entity will have DDR data for one BES
Element and at least one additional BES Element per 3,000 MW of its historical simultaneous
peak System Demand.
Rationale for R6:
DDR is used to measure transient response to System Disturbances during a relatively balanced
post-fault condition. Therefore, it is sufficient to provide a phase-to-neutral voltage or positive
sequence voltage. The electrical quantities can be determined (calculated, derived, etc.).
Because all of the BES buses within a location are at the same frequency, one frequency
measurement is adequate.
The data requirements for PRC-002-2 are based on a System configuration assuming all
normally closed circuit breakers on a BES bus are closed.
Rationale for R7:
A crucial part of wide-area Disturbance analysis is understanding the dynamic response of
generating resources. Therefore, it is necessary for Generator Owners to have DDR at either the
high- or low-side of the generator step-up transformer (GSU) measuring the specified electrical
quantities to adequately capture generator response. This standard defines the ‘what’ of DDR,
not the ‘how’. Generator Owners may install this capability or, where the Transmission Owners
already have suitable DDR data, contract with the Transmission Owner. However, the
Generator Owner is still responsible for the provision of this data.
Rationale for R8:
Large scale System outages generally are an evolving sequence of events that occur over an
extended period of time, making DDR data essential for event analysis. Data available pre- and
post-contingency helps identify the causes and effects of each event leading to outages.
Therefore, continuous recording and storage are necessary to ensure sufficient data is available
for the entire event.
Page 25 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
Existing DDR data recording across the BES may not record continuously. To accommodate its
use for the purposes of this standard, triggered records are acceptable if the equipment was
installed prior to the effective date of this standard. The frequency triggers are defined based
on the dynamic response associated with each Interconnection. The undervoltage trigger is
defined to capture possible delayed undervoltage conditions such as Fault Induced Delayed
Voltage Recovery (FIDVR).
Rationale for R9:
An input sampling rate of at least 960 samples per second, which corresponds to 16 samples
per cycle on the input side of the DDR equipment, ensures adequate accuracy for calculation of
recorded measurements such as complex voltage and frequency.
An output recording rate of electrical quantities of at least 30 times per second refers to the
recording and measurement calculation rate of the device. Recorded measurements of at least
30 times per second provide adequate recording speed to monitor the low frequency
oscillations typically of interest during power System Disturbances.
Rationale for R10:
Time synchronization of Disturbance monitoring data is essential for time alignment of large
volumes of geographically dispersed records from diverse recording sources. Coordinated
Universal Time (UTC) is a recognized time standard that utilizes atomic clocks for generating
precision time measurements. All data must be provided in UTC formatted time either with or
without the local time offset, expressed as a negative number (the difference between UTC and
the local time zone where the measurements are recorded).
Accuracy of time synchronization applies only to the clock used for synchronizing the
monitoring equipment. The equipment used to measure the electrical quantities must be time
synchronized to ± 2 ms accuracy; however, accuracy of the application of this time stamp and
therefore the accuracy of the data itself is not mandated. This is because of inherent delays
associated with measuring the electrical quantities and events such as breaker closing,
measurement transport delays, algorithm and measurement calculation techniques, etc.
Ensuring that the monitoring devices internal clocks are within ± 2 ms accuracy will suffice with
respect to providing time synchronized data.
Rationale for R11:
Wide-area Disturbance analysis includes data recording from many devices and entities.
Standardized formatting and naming conventions of these files significantly improves timely
analysis.
Providing the data within 30-calendar days (or the granted extension time), subject to Part 11.1,
allows for reasonable time to collect the data and perform any necessary computations or
formatting.
Data is required to be retrievable for 10-calendar days inclusive of the day the data was
recorded, i.e. a 10-calendar day rolling window of available data. Data hold requests are
usually initiated the same or next day following a major event for which data is requested. A 10-

Page 26 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
calendar day time frame provides a practical limit on the duration of data required to be stored
and informs the requesting entities as to how long the data will be available. The requestor of
data has to be aware of the Part 11.1 10-calendar day retrievability because requiring data
retention for a longer period of time is expensive and unnecessary.
SER data shall be provided in a simple ASCII .CSV format as outlined in Attachment 2. Either
equipment can provide the data or a simple conversion program can be used to convert files
into this format. This will significantly improve the data format for event records, enabling the
use of software tools for analyzing the SER data.
Part 11.4 specifies FR and DDR data files be provided in conformance with IEEE C37.111, IEEE
Standard for Common Format for Transient Exchange (COMTRADE), revision 1999 or later. The
use of IEEE C37.111-1999 or later is well established in the industry. C37.111-2013 is a version
of COMTRADE that includes an annex describing the application of the COMTRADE standard to
synchrophasor data; however, version C37.111-1999 is commonly used in the industry today.
Part 11.5 uses a standardized naming format, C37.232-2011, IEEE Standard for Common Format
for Naming Time Sequence Data Files (COMNAME), for providing Disturbance monitoring data.
This file format allows a streamlined analysis of large Disturbances, and includes critical records
such as local time offset associated with the synchronization of the data.
Rationale for R12:
Each Transmission Owner and Generator Owner who owns equipment used for collecting the
data required for this standard must repair any failures within 90-calendar days to ensure that
adequate data is available for event analysis. If the Disturbance monitoring capability cannot be
restored within 90-calendar days (e.g. budget cycle, service crews, vendors, needed outages,
etc.), the entity must develop a Corrective Action Plan (CAP) for restoring the data recording
capability. The timeline required for the CAP depends on the entity and the type of data
required. It is treated as a failure if the recording capability is out of service for maintenance
and/or testing for greater than 90-calendar days. An outage of the monitored BES Element
does not constitute a failure of the Disturbance monitoring capability.

Page 27 of 38

PRC-002-2 — Disturbance Monitoring and Reporting Requirements
Guidelines and Technical Basis Section

Introduction
The emphasis of PRC-002-2 is not on how Disturbance monitoring data is captured, but what
Bulk Electric System data is captured. There are a variety of ways to capture the data PRC-002-2
addresses, and existing and currently available equipment can meet the requirements of this
standard. PRC-002-2 also addresses the importance of addressing the availability of Disturbance
monitoring capability to ensure the completeness of BES data capture.
The data requirements for PRC-002-2 are based on a System configuration assuming all
normally closed circuit breakers on a bus are closed.
PRC-002-2 addresses “what” data is recorded, not “how” it is recorded.
Guideline for Requirement R1:
Sequence of events and fault recording for the analysis, reconstruction, and reporting of
System Disturbances is important. However, SER and FR data is not required at every BES bus
on the BES to conduct adequate or thorough analysis of a Disturbance. As major tools of event
analysis, the time synchronized time stamp for a breaker change of state and the recorded
waveforms of voltage and current for individual circuits allows the precise reconstruction of
events of both localized and wide-area Disturbances.
More quality information is always better than less when performing event analysis. However,
100 percent coverage of all BES Elements is not practical nor required for effective analysis of
wide-area Disturbances. Therefore, selectivity of required BES buses to monitor is important for
the following reasons:
1. Identify key BES buses with breakers where crucial information is available when
required.
2. Avoid excessive overlap of coverage.
3. Avoid gaps in critical coverage.
4. Provide coverage of BES Elements that could propagate a Disturbance.
5. Avoid mandates to cover BES Elements that are more likely to be a casualty of a
Disturbance rather than a cause.
6. Establish selection criteria to provide effective coverage in different regions of the
continent.
The major characteristics available to determine the selection process are:
1.
2.
3.
4.

System voltage level;
The number of Transmission Lines into a substation or switchyard;
The number and size of connected generating units;
The available short circuit levels.

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Although it is straightforward to establish criteria for the application of identified BES buses,
analysis was required to establish a sound technical basis to fulfill the required objectives.
To answer these questions and establish criteria for BES buses of SER and FR, the DMSDT
established a sub-team referred to as the Monitored Value Analysis Team (MVA Team). The
MVA Team collected information from a wide variety of Transmission Systems throughout the
continent to analyze Transmission buses by the characteristics previously identified for the
selection process.
The MVA Team learned that the development of criteria is not possible for adequate SER and
FR coverage, based solely upon simple, bright line characteristics, such as the number of lines
into a substation or switchyard at a particular voltage level or at a set level of short circuit
current. To provide the appropriate coverage, a relatively simple but effective Methodology for
Selecting Buses for Capturing Sequence of Events Recording (SER) and Fault Recording (FR) Data
was developed. This Procedure, included as Attachment 1, assists entities in fulfilling
Requirement R1 of the standard.
The Methodology for Selecting Buses for Capturing Sequence of Events Recording (SER) and
Fault Recording (FR) Data is weighted to buses with higher short circuit levels. This is chosen for
the following reasons:
1.
2.
3.
4.

The method is voltage level independent.
It is likely to select buses near large generation centers.
It is likely to select buses where delayed clearing can cause Cascading.
Selected buses directly correlate to the Universal Power Transfer equation: Lower
Impedance – increased power flows – greater System impact.

To perform the calculations of Attachment 1, the following information below is required and
the following steps (provided in summary form) are required for Systems with more than 11
BES buses with three phase short circuit levels above 1,500 MVA.
1. Total number of BES buses in the Transmission System under evaluation.
a. Only tangible substation or switchyard buses are included.
b. Pseudo buses created for analysis purposes in System models are excluded.
2. Determine the three phase short circuit MVA for each BES bus.
3. Exclude BES buses from the list with short circuit levels below 1,500 MVA.
4. Determine the median short circuit for the top 11 BES buses on the list (position number
6).
5. Multiply median short circuit level by 20 percent.
6. Reduce the list of BES buses to those with short circuit levels higher than 20 percent of
the median.
7. Apply SER and FR at BES buses with short circuit levels in the top 10 percent of the list
(from 6).

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8. Apply SER and FR at BES buses at an additional 10 percent of the list using engineering
judgment, and allowing flexibility to factor in the following considerations:
 Electrically distant BES buses or electrically distant from other DME devices
 Voltage sensitive areas
 Cohesive load and generation zones
 BES buses with a relatively high number of incident Transmission circuits
 BES buses with reactive power devices
 Major facilities interconnecting outside the Transmission Owner’s area.
For event analysis purposes, more valuable information is attained about generators and their
response to System events pre- and post-contingency through DDR data versus SER or FR
records. SER data of the opening of the primary generator output interrupting devices (e.g.
synchronizing breaker) may not reliably indicate the actual time that a generator tripped; for
instance, when it trips on reverse power after loss of its prime mover (e.g. combustion or steam
turbine). As a result, this standard only requires DDR data.
The re-evaluation interval of five years was chosen based on the experience of the DMSDT to
address changing System configurations while creating balance in the frequency of reevaluations.
Guideline for Requirement R2:
Analyses of wide-area Disturbances often begin by evaluation of SERs to help determine the
initiating event(s) and follow the Disturbance propagation. Recording of breaker operations
help determine the interruption of line flows while generator loading is best determined by
DDR data, since generator loading can be essentially zero regardless of breaker position.
However, generator breakers directly connected to an identified BES bus are required to have
SER data captured. It is important in event analysis to know when a BES bus is cleared
regardless of a generator’s loading.
Generator Owners are included in this requirement because a Generator Owner may, in some
instances, own breakers directly connected to the Transmission Owner’s BES bus.
Guideline for Requirement R3:
The BES buses for which FR data is required are determined based on the methodology
described in Attachment 1 of the standard. The BES Elements connected to those BES buses for
which FR data is required include:
-

Transformers with a low-side operating voltage of 100kV or above
Transmission Lines

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
Only those BES Elements that are identified as BES as defined in the latest in effect NERC
definition are to be monitored. For example, radial lines or transformers with low-side voltage
less than 100kV are not included.
FR data must be determinable from each terminal of a BES Element connected to applicable
BES buses.
Generator step-up transformers (GSU) are excluded from the above based on the following:
-

Current contribution from a generator in case of fault on the Transmission System will
be captured by FR data on the Transmission System.
For faults on the interconnection to generating facilities it is sufficient to have fault
current data from the Transmission station end of the interconnection. Current
contribution from a generator can be readily calculated if needed.

The DMSDT, after consulting with NERC’s Event Analysis group, determined that DDR data from
selected generator locations was more important for event analysis than FR data.
Recording of Electrical Quantities
For effective fault analysis it is necessary to know values of all phase and neutral currents and
all phase-to-neutral voltages. Based on such FR data it is possible to determine all fault types.
FR data also augments SERs in evaluating circuit breaker operation.
Current Recordings
The required electrical quantities are normally directly measured. Certain quantities can be
derived if sufficient data is measured, for example residual or neutral currents.
Since a Transmission System is generally well balanced, with phase currents having essentially
similar magnitudes and phase angle differences of 120○, during normal conditions there is
negligible neutral (residual) current. In case of a ground fault the resulting phase current
imbalance produces residual current that can be either measured or calculated.
Neutral current, also known as ground or residual current Ir, is calculated as a sum of vectors of
three phase currents:
Ir =3•I0 =IA +IB +IC
I0 - Zero-sequence current
IA, IB, IC - Phase current (vectors)
Another example of how required electrical quantities can be derived is based on Kirchhoff’s
Law. Fault currents for one of the BES Elements connected to a particular BES bus can be
derived as a vectorial sum of fault currents recorded at the other BES Elements connected to
that BES bus.
Voltage Recordings

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
Voltages are to be recorded or accurately determined at applicable BES buses.
Guideline for Requirement R4:
Pre- and post-trigger fault data along with the SER breaker data, all time stamped to a common
clock at millisecond accuracy, aid in the analysis of protection System operations after a fault to
determine if a protection System operated as designed. Generally speaking, BES faults persist
for a very short time period, approximately 1 to 30 cycles, thus a 30-cycle record length
provides adequate data. Multiple records allow for legacy microprocessor relays which, when
time synchronized to a common clock, are capable of providing adequate fault data but not
capable of providing fault data in a single record with 30-contiguous cycles total.
A minimum recording rate of 16 samples per cycle is required to get accurate waveforms and to
get 1 millisecond resolution for any digital input which may be used for FR.
FR triggers can be set so that when the monitored value on the recording device goes above or
below the trigger value, data is recorded. Requirement R4, sub-Part 4.3.1 specifies a neutral
(residual) overcurrent trigger for ground faults. Requirement R4, sub-Part 4.3.2 specifies a
phase undervoltage or overcurrent trigger for phase-to-phase faults.
Guideline for Requirement R5:
DDR data is used for wide-area Disturbance monitoring to determine the System’s
electromechanical transient and post-transient response and validate System model
performance. DDR is typically located based on strategic studies which include angular,
frequency, voltage, and oscillation stability. However, for adequately monitoring the System’s
dynamic response and ensuring sufficient coverage to determine System performance, DDR is
required for key BES Elements in addition to a minimum requirement of DDR coverage.
Each Responsible Entity (PC or RC) is required to identify sufficient DDR data capture for, at a
minimum, one BES Element and then one additional BES Element per 3,000 MW of historical
simultaneous peak System Demand. This DDR data is included to provide adequate System
wide coverage across an Interconnection. To clarify, if any of the key BES Elements requiring
DDR monitoring are within the Responsible Entity’s area, DDR data capability is required. If a
Responsible Entity (PC or RC) does not meet the requirements of Part 5.1, additional coverage
had to be specified.
Loss of large generating resources poses a frequency and angular stability risk for all
Interconnections across North America. Data capturing the dynamic response of these
machines during a Disturbance helps the analysis of large Disturbances. Having data regarding
generator dynamic response to Disturbances greatly improves understanding of why an event
occurs rather than what occurred. To determine and provide the basis for unit size criteria, the
DMSDT acquired specific generating unit data from NERC’s Generating Availability Data System
(GADS) program. The data contained generating unit size information for each generating unit
in North America which was reported in 2013 to the NERC GADS program. The DMSDT analyzed
the spreadsheet data to determine: (i) how many units were above or below selected size
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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
thresholds; and (ii) the aggregate sum of the ratings of the units within the boundaries of those
thresholds. Statistical information about this data was then produced, i.e. averages, means and
percentages. The DMSDT determined the following basic information about the generating
units of interest (current North America fleet, i.e. units reporting in 2013) included in the
spreadsheet:





The number of individual generating units in total included in the spreadsheet.
The number of individual generating units rated at 20 MW or larger included in the
spreadsheet. These units would generally require that their owners be registered as
GOs in the NERC CMEP.
The total number of units within selected size boundaries.
The aggregate sum of ratings, in MWs, of the units within the boundaries of those
thresholds.

The information in the spreadsheet does not provide information by which the plant
information location of each unit can be determined, i.e. the DMSDT could not use the
information to determine which units were located together at a given generation site or
facility.
From this information, the DMSDT was able to reasonably speculate the generating unit size
thresholds proposed in Requirement R5, sub-Part 5.1.1 of the standard. Generating resources
intended for DDR data recording are those individual units with gross nameplate ratings
“greater than or equal to 500 MVA”. The 500 MVA individual unit size threshold was selected
because this number roughly accounts for 47 percent of the generating capacity in NERC
footprint while only requiring DDR coverage on about 12.5 percent of the generating units. As
mentioned, there was no data pertaining to unit location for aggregating plant/facility sizes.
However, Requirement R5, sub-Part 5.1.1 is included to capture larger units located at large
generating plants which could pose a stability risk to the System if multiple large units were lost
due to electrical or non-electrical contingencies. For generating plants, each individual
generator at the plant/facility with a gross nameplate rating greater than or equal to 300 MVA
must have DDR where the gross nameplate rating of the plant/facility is greater than or equal
to 1,000 MVA. The 300 MVA threshold was chosen based on the DMSDT’s judgment and
experience. The incremental impact to the number of units requiring monitoring is expected to
be relatively low. For combined cycle plants where only one generator has a rating greater
than or equal to 300MVA, that is the only generator that would need DDR.
Permanent System Operating Limits (SOLs) are used to operate the System within reliable and
secure limits. In particular, SOLs related to angular or voltage stability have a significant impact
on BES reliability and performance. Therefore, at least one BES Element of an SOL should be
monitored.
The draft standard requires “One or more BES Elements that are part of an Interconnection
Reliability Operating Limits (IROLs).” Interconnection Reliability Operating Limits (IROLs) are
included because the risk of violating these limits poses a risk to System stability and the
potential for cascading outages. IROLs may be defined by a single or multiple monitored BES
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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
Element(s) and contingent BES Element(s). The standard does not dictate selection of the
contingent and/or monitored BES Elements. Rather the Drafting Team believes this
determination is best made by the Responsible Entity for each IROL considered based on the
severity of violating this IROL.
Locations where an undervoltage load shedding (UVLS) program is deployed are prone to
voltage instability since they are generally areas of significant Demand. The Responsible Entity
(PC or RC) will identify these areas where a UVLS is in service and identify a useful and effective
BES Element to monitor for DDR such that action of the UVLS or voltage instability on the BES
could be captured. For example, a major 500kV or 230kV substation on the EHV System close to
the load pocket where the UVLS is deployed would likely be a valuable electrical location for
DDR coverage and would aid in post-Disturbance analysis of the load area’s response to large
System excursions (voltage, frequency, etc.).
Guideline for Requirement R6:
DDR data shows transient response to System Disturbances after a fault is cleared (post-fault),
under a relatively balanced operating condition. Therefore, it is sufficient to provide a single
phase-to-neutral voltage or positive sequence voltage. Recording of all three phases of a circuit
is not required, although this may be used to compute and record the positive sequence
voltage.
The bus where a voltage measurement is required is based on the list of BES Elements defined
by the Responsible Entity (PC or RC) in Requirement R5. The intent of the standard is not to
require a separate voltage measurement of each BES Element where a common bus voltage
measurement is available. For example, a breaker-and-a-half or double-bus configuration with a
North (or East) Bus and South (or West) Bus, would require both buses to have voltage
recording because either can be taken out of service indefinitely with the targeted BES Element
remaining in service. This may be accomplished either by recording both bus voltages
separately, or by providing a selector switch to connect either of the bus voltage sources to a
single recording input of the DDR device. This component of the requirement is therefore
included to mitigate the potential of failed frequency, phase angle, real power, and reactive
power calculations due to voltage measurements removed from service while sufficient voltage
measurement is actually available during these operating conditions.
It must be emphasized that the data requirements for PRC-002-2 are based on a System
configuration assuming all normally closed circuit breakers on a bus are closed.
When current recording is required, it should be on the same phase as the voltage recording
taken at the location if a single phase-to-neutral voltage is provided. Positive sequence current
recording is also acceptable.

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
For all circuits where current recording is required, Real and Reactive Power will be recorded on
a three phase basis. These recordings may be derived either from phase quantities or from
positive sequence quantities.
Guideline for Requirement R7:
All Guidelines specified for Requirement R6 apply to Requirement R7. Since either the high- or
low-side windings of the generator step-up transformer (GSU) may be connected in delta,
phase-to-phase voltage recording is an acceptable voltage recording. As was explained in the
Guideline for Requirement R6, the BES is operating under a relatively balanced operating
condition and, if needed, phase-to-neutral quantities can be derived from phase-to-phase
quantities.
Again it must be emphasized that the data requirements for PRC-002-2 are based on a System
configuration assuming all normally closed circuit breakers on a bus are closed.
Guideline for Requirement R8:
Wide-area System outages are generally an evolving sequence of events that occur over an
extended period of time, making DDR data essential for event analysis. Pre- and postcontingency data helps identify the causes and effects of each event leading to the outages.
This drives a need for continuous recording and storage to ensure sufficient data is available for
the entire Disturbance.
Transmission Owners and Generator Owners are required to have continuous DDR for the BES
Elements identified in Requirement R6. However, this requirement recognizes that legacy
equipment may exist for some BES Elements that do not have continuous data recording
capabilities. For equipment that was installed prior to the effective date of the standard,
triggered DDR records of three minutes are acceptable using at least one of the trigger types
specified in Requirement R8, Part 8.2:




Off nominal frequency triggers are used to capture high- or low-frequency excursions of
significant size based on the Interconnection size and inertia.
Rate of change of frequency triggers are used to capture major changes in System
frequency which could be caused by large changes in generation or load, or possibly
changes in System impedance.
The undervoltage trigger specified in this standard is provided to capture possible
sustained undervoltage conditions such as Fault Induced Delayed Voltage Recovery
(FIDVR) events. A sustained voltage of 85 percent is outside normal schedule operating
voltages and is sufficiently low to capture abnormal voltage conditions on the BES.

Guideline for Requirement R9:
DDR data contains the dynamic response of a power System to a Disturbance and is used for
analyzing complex power System events. This recording is typically used to capture short-term

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
and long-term Disturbances, such as a power swing. Since the data of interest is changing over
time, DDR data is normally stored in the form of RMS values or phasor values, as opposed to
directly sampled data as found in FR data.
The issue of the sampling rate used in a recording instrument is quite important for at least two
reasons: the anti-aliasing filter selection and accuracy of signal representation. The anti-aliasing
filter selection is associated with the requirement of a sampling rate at least twice the highest
frequency of a sampled signal. At the same time, the accuracy of signal representation is also
dependent on the selection of the sampling rate. In general, the higher the sampling rate, the
better the representation. In the abnormal conditions of interest (e.g. faults or other
Disturbances); the input signal may contain frequencies in the range of 0-400 Hz. Hence, the
rate of 960 samples per second (16 samples/cycle) is considered an adequate sampling rate
that satisfies the input signal requirements.
In general, dynamic events of interest are: inter-area oscillations, local generator oscillations,
wind turbine generator torsional modes, HVDC control modes, exciter control modes, and
steam turbine torsional modes. Their frequencies range from 0.1-20 Hz. In order to reconstruct
these dynamic events, a minimum recording time of 30 times per second is required.
Guideline for Requirement R10: Time synchronization of Disturbance monitoring data allows
for the time alignment of large volumes of geographically dispersed data records from diverse
recording sources. A universally recognized time standard is necessary to provide the
foundation for this alignment. Coordinated Universal Time (UTC) is the foundation used for the
time alignment of records. It is an international time standard utilizing atomic clocks for
generating precision time measurements at fractions of a second levels. The local time offset,
expressed as a negative number, is the difference between UTC and the local time zone where
the measurements are recorded.
Accuracy of time synchronization applies only to the clock used for synchronizing the
monitoring equipment.
Time synchronization accuracy is specified in response to Recommendation 12b in the NERC
August, 2003, Blackout Final NERC Report Section V Conclusions and Recommendations:
“Recommendation 12b: Facilities owners shall, in accordance with regional criteria, upgrade
existing dynamic recorders to include GPS time synchronization…”
Also, from the U.S.-Canada Power System Outage Task Force Interim Report: Causes of the
August 14th Blackout, November 2003, in the United States and Canada, page 103:
“Establishing a precise and accurate sequence of outage-related events was a critical building
block for the other parts of the investigation. One of the key problems in developing this
sequence was that although much of the data pertinent to an event was time-stamped, there
was some variance from source to source in how the time-stamping was done, and not all of
the time-stamps were synchronized…”

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
From NPCC’s SP6 Report Synchronized Event Data Reporting, revised March 31, 2005, the
investigation by the authoring working group revealed that existing GPS receivers can be
expected to provide a time code output which has an uncertainty on the order of 1 millisecond,
uncertainty being a quantitative descriptor.
Guideline for Requirement R11:
This requirement directs the applicable entities, upon requests from the Responsible Entity,
Regional Entity or NERC, to provide SER and FR data for BES buses determined in Requirement
R1 and DDR data for BES Elements determined as per Requirement R5. To facilitate the analysis
of BES Disturbances, it is important that the data is provided to the requestor within a
reasonable period of time.
Requirement R11, Part 11.1 specifies the maximum time frame of 30-calendar days to provide
the data. Thirty calendar days is a reasonable time frame to allow for the collection of data, and
submission to the requestor. An entity may request an extension of the 30-day submission
requirement. If granted by the requestor, the entity must submit the data within the approved
extended time.
Requirement R11, Part 11.2 specifies that the minimum time period of 10-calendar days
inclusive of the day the data was recorded for which the data will be retrievable. With the
equipment in use that has the capability of recording data, having the data retrievable for the
10-calendar days is realistic and doable. It is important to note that applicable entities should
account for any expected delays in retrieving data and this may require devices to have data
available for more than 10 days. To clarify the 10-calendar day time frame, an incident occurs
on Day 1. If a request for data is made on Day 6, then that data has to be provided to the
requestor within 30-calendar days after a request or a granted time extension. However, if a
request for the data is made on Day 11, that is outside the 10-calendar days specified in the
requirement, and an entity would not be out of compliance if it did not have the data.
Requirement R11, Part 11.3 specifies a Comma Separated Value (CSV) format according to
Attachment 2 for the SER data. It is necessary to establish a standard format as it will be
incorporated with other submitted data to provide a detailed sequence of events timeline of a
power System Disturbance.
Requirement R11, Part 11.4 specifies the IEEE C37.111 COMTRADE format for the FR and DDR
data. The IEEE C37.111 is the Standard for Common Format for Transient Data Exchange and is
well established in the industry. It is necessary to specify a standard format as multiple
submissions of data from many sources will be incorporated to provide a detailed analysis of a
power System Disturbance. The latest revision of COMTRADE (C37.111-2013) includes an
annex describing the application of the COMTRADE standard to synchophasor data.
Requirement R11, Part 11.5 specifies the IEEE C37.232 COMNAME format for naming the data
files of the SER, FR and DDR. The IEEE C37.232 is the Standard for Common Format for Naming
Time Sequence Data Files. The first version was approved in 2007. From the August 14, 2003
blackout there were thousands of Fault Recording data files collected. The collected data files

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PRC-002-2 — Disturbance Monitoring and Reporting Requirements
did not have a common naming convention and it was therefore difficult to discern which files
came from which utilities and which ones were captured by which devices. The lack of a
common naming practice seriously hindered the investigation process. Subsequently, and in its
initial report on the blackout, NERC stressed the need for having a common naming practice
and listed it as one of its top ten recommendations.
Guideline for Requirement R12:
This requirement directs the respective owners of Transmission and Generator equipment to
be alert to the proper functioning of equipment used for SER, FR, and DDR data capabilities for
the BES buses and BES Elements, which were established in Requirements R1 and R5. The
owners are to restore the capability within 90-calendar days of discovery of a failure. This
requirement is structured to recognize that the existence of a “reasonable” amount of
capability out-of-service does not result in lack of sufficient data for coverage of the System.
Furthermore, 90-calendar days is typically sufficient time for repair or maintenance to be
performed. However, in recognition of the fact that there may be occasions for which it is not
possible to restore the capability within 90-calendar days, the requirement further provides
that, for such cases, the entity submit a Corrective Action Plan (CAP) to the Regional Entity and
implement it. These actions are considered to be appropriate to provide for robust and
adequate data availability.

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* FOR INFORMATIONAL PURPOSES ONLY *
Enforcement Dates: Standard PRC-002-2 — Disturbance Monitoring and Reporting Requirements
United States
Standard

Requirement

PRC-002-2

All

Enforcement Date

Inactive Date

This standard has not yet been approved by the applicable regulatory authority.

Printed On: May 21, 2015, 12:01 PM