NERC Petition (without Exhibits)

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
PRC-002-2
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile

Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Associate General Counsel
William H. Edwards
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]
[email protected]

Counsel for the North American Electric
Reliability Corporation

December 15, 2014

TABLE OF CONTENTS

I.

EXECUTIVE SUMMARY .................................................................................................... 2

II.

NOTICES AND COMMUNICATIONS ................................................................................ 3

III. BACKGROUND .................................................................................................................... 3
A.

Regulatory Framework ..................................................................................................... 3

B.

NERC Reliability Standards Development Procedure ..................................................... 4

C.

2003 Blackout Report Recommendations No. 24 and No. 28 ......................................... 5
1.

NERC Board Recommendation 12 and 2003 Blackout Recommendation No. 28 ...... 6

2.

NERC Board Recommendation 14 and 2003 Blackout Recommendation No. 24 ...... 9

D.

History of PRC-002 and PRC-018 ................................................................................. 10

E.

History of Project 2007-11 Disturbance Monitoring ..................................................... 12

IV. JUSTIFICATION FOR APPROVAL................................................................................... 12
A.

Disturbance Monitoring ................................................................................................. 13

B.

Proposed Reliability Standard PRC-002-2 ..................................................................... 14

C.
V.

1.

Purpose of and Types of Data Covered in Proposed PRC-002-2 ............................... 14

2.

Applicable Entities ..................................................................................................... 16

3.

Proposed Requirements .............................................................................................. 17

4.

Improvements and Consideration of Commission Directives .................................... 35
Enforceability of Proposed Reliability Standard ............................................................ 37

CONCLUSION ..................................................................................................................... 37

Exhibit A

Proposed Reliability Standard PRC-002-2

Exhibit B

Implementation Plan

Exhibit C

Mapping Document

Exhibit D

Order No. 672 Criteria

Exhibit E

Consideration of Issues and Directives

Exhibit F

Analysis of Violation Risk Factors and Violation Severity Levels

Exhibit G

Summary of Development History and Complete Record of Development

Exhibit H

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
PRC-002-2
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 2 of
the Federal Energy Regulatory Commission’s (“FERC” or “Commission”) regulations, the North
American Electric Reliability Corporation (“NERC”) 3 hereby submits for Commission approval
proposed Reliability Standard PRC-002-2 (Disturbance Monitoring and Reporting
Requirements) (Exhibit A). NERC requests that the Commission approve the proposed
Reliability Standard and find that it is just, reasonable, not unduly discriminatory or preferential,
and in the public interest. 4 NERC also requests approval of: (i) the Implementation Plan for the
proposed Reliability Standard (Exhibit B); (ii) the associated Violation Risk Factors (“VRFs”)
and Violation Severity Levels (“VSLs”) (Exhibits A and F); and (iii) the retirement of Reliability
Standards PRC-002-1 (Define Regional Disturbance Monitoring and Reporting Requirements)

1

16 U.S.C. § 824o (2012).
18 C.F.R. § 39.5 (2014).
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).
4
Unless otherwise designated, capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards (“NERC Glossary of Terms”), available at
http://www.nerc.com/files/Glossary_of_Terms.pdf.
2

1

and PRC-018-1 (Disturbance Monitoring Equipment Installation and Data Reporting) as listed in
the Implementation Plan.
As required by Section 39.5(a) 5 of the Commission’s regulations, this petition presents
the technical basis and purpose of proposed Reliability Standard PRC-002-2, a summary of the
development history (Exhibit G), and a demonstration that the proposed Reliability Standard
meets the criteria identified by the Commission in Order No. 672 6 (Exhibit D). This petition also
provides background on Recommendations No. 24 and No. 28 in the U.S.-Canada Power System
Outage Task Force (“Task Force”), Final Report on the August 14, 2003 Blackout in the United
States and Canada: Causes and Recommendations (“Final Blackout Report”) and how the
proposed Reliability Standard implements these Task Force Recommendations. 7 The NERC
Board of Trustees (“NERC Board”) adopted proposed Reliability Standard PRC-002-2 on
November 13, 2014.
I.

EXECUTIVE SUMMARY
Proposed PRC-002-2 contains the Requirements necessary to facilitate the analysis of

Disturbances on the Bulk-Power System. The proposed Reliability Standard defines what
sequence of events (“SER”) recording, fault recording (“FR”), and dynamic Disturbance
recording (“DDR”) data should be recorded and how it should be reported.

5

18 C.F.R. § 39.5(a) (2014).
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
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 262, 321-37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
7
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 (Apr. 2004), available at
http://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/BlackoutFinal-Web.pdf.
6

2

II.

NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the

following: 8

Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Associate General Counsel
William H. Edwards*
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]
[email protected]

III.

Valerie L. Agnew*
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, 9 Congress entrusted the Commission with
the duties of approving and enforcing rules to ensure the reliability of the Nation’s Bulk-Power
System, and with the duties of 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) 10 of the FPA states that all users, owners, and
operators of the Bulk-Power System in the United States will be subject to Commission-

8

Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203 (2014), to allow the inclusion
of more than two persons on the service list in this proceeding.
9
16 U.S.C. § 824o (2012).
10
Id. § 824(b)(1).

3

approved Reliability Standards. Section 215(d)(5) 11 of the FPA authorizes the Commission to
order the ERO to submit a new or modified Reliability Standard. Section 39.5(a) 12 of the
Commission’s regulations requires the ERO to file with the Commission for its approval each
Reliability Standard that the ERO proposes should become mandatory and enforceable in the
United States, and each modification to a Reliability Standard that the ERO proposes should be
made effective.
The Commission has 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 13 and Section 39.5(c) 14 of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the
content of a Reliability Standard.
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. 15 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards

11

Id. § 824o(d)(5).
18 C.F.R. § 39.5(a).
13
16 U.S.C. § 824o(d)(2).
14
18 C.F.R. § 39.5(c)(1).
15
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672 at P 334, FERC Stats. &
Regs. ¶ 31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006) (“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 FERC.”).
12

4

Development) of its Rules of Procedure and the NERC Standard Processes Manual. 16 In its
order certifying NERC as the Commission’s Electric Reliability Organization, 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 17
and thus satisfies certain of the criteria for approving Reliability Standards. 18 The development
process is open to any person or entity with a legitimate interest in the reliability of the BulkPower System. NERC considers the comments of all stakeholders, and stakeholders must
approve, and the NERC Board of Trustees must adopt a Reliability Standard before the
Reliability Standard is submitted to the Commission for approval.
C.

2003 Blackout Report Recommendations No. 24 and No. 28

On August 14, 2003, large portions of the Midwest and Northeast United States and
Ontario, Canada, experienced an electric power blackout (“2003 Blackout”). 19 The next day, the
joint U.S.-Canada Task Force was established to investigate the causes of the blackout and how
to reduce the possibility of future outages. The Task Force’s work was divided into two phases
as follows:
•

Phase I: Investigate the outage to determine its causes and why it was not
contained.

•

Phase II: Develop recommendations to reduce the possibility of future outages
and minimize the scope of any that occur. 20

16

The NERC Rules of Procedure are available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
17
116 FERC ¶ 61,062 at P 250.
18
Order No. 672 at PP 268, 270.
19
U.S.-Canada Power System Outage Task Force, Interim Report: Causes of the
August 14th Blackout in the United States and Canada at 1 (Nov. 2003) (“Interim Blackout
Report”), available at http://emp.lbl.gov/sites/all/files/interim-rpt-Aug-14-blkout-03.pdf.
20
Id.

5

In November 2003, the Task Force issued the Interim Blackout Report, describing its
investigation and findings and identifying the causes of the blackout. 21
1. NERC Board Recommendation 12 and 2003 Blackout Recommendation
No. 28
On February 10, 2004, after taking the findings of the Interim Blackout Report into
account, the NERC Board approved a series of actions and strategic and technical initiatives
intended to protect the reliability of the North American Bulk Electric System (“NERC Board
Recommendations”). 22 Among its actions, the NERC Board issued Recommendation 12 to
install additional time-synchronized recording devices as needed and Recommendation 14 to
improve system modeling data and data exchange practices.
NERC Board Recommendation 12a directed the reliability regions to define, within one
year, regional criteria for the application of synchronized recording devices in power plants and
substations. Regions were requested to facilitate the installation of an appropriate number, type
and location of devices within the region as soon as practical to allow accurate recording of
future system Disturbances and to facilitate benchmarking of simulation studies by comparison
to actual Disturbances. 23 NERC Board Recommendation 12b directed facilities owners, in
accordance with regional criteria, to upgrade existing dynamic recorders to include Global
Positioning Satellite (“GPS”) time synchronization and, as necessary, install additional dynamic
recorders. 24

21

Id.
Minutes and agenda materials for the February 10, 2004 meeting of the NERC Board of Trustees are
available at http://www.nerc.com/gov/bot/Pages/AgendasHighlightsMinutes.aspx. See also Final Blackout Report at
Appendix D NERC Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts, available at
http://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/BlackoutFinal-Web.pdf.
23
NERC Board Actions at 207.
24
Id.
22

6

The Final Blackout Report, issued on April 5, 2004, verifies and expands the findings of
the Interim Blackout Report. On certain subjects, the Task Force advocated for broader
measures than those in the NERC Board Recommendations, including in Task Force
Recommendation No. 28 to require use of time-synchronized data recorders. 25 The Task Force
explained that a valuable lesson from the 2003 Blackout is the importance of having timesynchronized system data recorders. The Task Force noted that the investigation would have
been significantly faster and easier if there had been wider use of synchronized data recording
devices. The Task Force also stated that NERC Planning Standard I.F, Disturbance Monitoring,
required the use of recording devices for Disturbance analysis. 26
On the day of the blackout, time recorders were frequently used, but not synchronized to
a time standard. The Task Force explained that, at a relatively modest cost, all digital fault
recorders, digital event recorders, and power system Disturbance recorders can and should be
time-stamped at the point of observation using a GPS synchronizing signal. The Task Force also
explained that recording and time synchronization equipment should be monitored and calibrated
to assure accuracy and reliability. The Task Force made the following four observations in Task
Force Recommendation No. 28 to provide a broader approach than that proposed by the NERC
Board:
A. FERC and appropriate authorities in Canada should require the
use of data recorders synchronized by signals from the Global
Positioning System (GPS) on all categories of facilities whose data
may be needed to investigate future system Disturbances, outages,
or blackouts.
B. NERC, reliability coordinators, control areas, and transmission
owners should determine where high speed power system
Disturbance recorders are needed on the system, and ensure that

25
26

Final Blackout Report at 162.
Id.

7

they are installed by December 31, 2004.
C. NERC should establish data recording protocols.
D. FERC and appropriate authorities in Canada should ensure that
the investments called for in this recommendation will be
recoverable through transmission rates.
Following through on the Task Force Recommendation No. 28, NERC addressed items
A, B, and C above through a single effort. The NERC Planning Committee’s Interconnection
Dynamics Working Group (“IDWG”) examined NERC’s Reliability Standards on Disturbance
monitoring as well as existing interconnection-wide practices and concluded that the NERC
Disturbance monitoring standards and related regional requirements were inadequate. The IDWG
developed a set of recommendations for specific improvements in its final report, Review of
Regional Disturbance Monitoring Equipment, which addresses both Recommendation 12 of the
NERC Board Recommendations and the Task Force Recommendation No. 28. 27 The NERC
Board adopted this report at its May 2005 meeting. 28 The report identified that the NERC
Disturbance monitoring standards addressed only new equipment and:
(1) do not address time synchronization on existing installations;
(2) do not specify the process for identifying locations;
(3) do not specify the process for ensuring additional installations; and
(4) do not specify that dynamic recording devices or sequence-of-event recorders are
necessary to meet Disturbance monitoring equipment requirements. 29

27

See NERC Planning Committee Mar. 16-17, 2005 Meeting, Agenda Item 6: IDWG Report at Att. A.
See NERC Board May 3, 2005 Meeting Complete Agenda Package, Agenda Item 11b: Review of Regional
Disturbance Monitoring Equipment ⎯ Recommendation 12a, available at
http://www.nerc.com/gov/bot/Agenda%20Minutes%20and%20Highlights%20DL/2005/BOT_Complete_Agenda_P
ackage_0505.pdf.
29
See NERC Board May 3, 2005 Meeting, Item 11b IDWG Presentation on Review of Regional
Disturbance Monitoring Equipment. This presentation is included in the Complete Agenda package
28

8

The report also identified that regional “Disturbance Monitoring” requirements and processes
were deficient and inconsistent among the regions. These recommendations and input from the
IDWG would translate into two Reliability Standards. Reliability Standard PRC-002-0 was
revised and separated into two Reliability Standards—PRC-002-1 (Define Regional Disturbance
Monitoring and Reporting Requirements) and PRC-018-1 (Disturbance Monitoring Equipment
Installation and Data Reporting). In the Task Force’s Final Report on Implementation of Task
Force Recommendations (“Blackout Implementation Report”), the Task Force noted that
completion and approval by applicable regulatory authorities in the United States and Canada of
any standard was required to fully implement Task Force Recommendation 28.A, 28.B, and
28.C. 30
2. NERC Board Recommendation 14 and 2003 Blackout Recommendation
No. 24
The NERC Board Recommendations also included Recommendation 14 to improve
system modeling data and data exchange practices. Recommendation 14 directs the regional
reliability councils to establish and begin implementing criteria and procedures for validating
data used in power flow models and dynamic simulations by benchmarking model data with
actual system performance. The Recommendation also instructed that validated modeling data
must be exchanged on an inter-regional basis as needed for reliable system planning and
operation.
Task Force Recommendation No. 24 relates to improving the quality of system modeling
data and data exchange practices. The Task Force states in Recommendation No. 24 that it
strongly supports NERC Board Recommendation 14. The Task Force further recommended that

30

See Blackout Implementation Report at 37 (Sept. 2006), available at
http://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/BlackoutFinalImplementationReport(2).pdf.

9

FERC and appropriate authorities in Canada require all generators, regardless of ownership, to
collect and submit generator data to NERC, using a regulator-approved template. The Task
Force noted that after-the-fact models developed to simulate the conditions and events in the
blackout established that the dynamic modeling assumptions for generator and load power
factors in regional planning and operating models were frequently inaccurate.
While NERC directly addressed Recommendation No. 24 through other standard
development work, a mandatory and enforceable Reliability Standard for Disturbance
monitoring further supports the implementation of this Trask Force Recommendation. The Task
Force noted in the Blackout Implementation Report:
…new [Board-approved] standards, along with standards previously
approved by the NERC Board of Trustees in February 2005 as part
of the “Version 0” standards, represent a comprehensive set of
standards for steady-state and dynamics system data reporting,
modeling and simulation, and model validation that address this
recommendation. 31
The Version 0 standards included PRC-002-0, which was not ultimately approved
by the Commission, as noted in Section D below.
D.

History of PRC-002 and PRC-018

On April 4, 2006, as modified on August 28, 2006, NERC submitted to the Commission
a petition seeking approval of an initial set of 107 proposed Reliability Standards. 32 NERC
included PRC-002-0 in its April 4th Petition. NERC replaced this version with PRC-002-1 and
also submitted PRC-018-1 for Commission approval in its August 28th Petition. 33 Both
requirements in the original version 0 standard were substantially revised and four new

31

Blackout Implementation Report at 35.
See NERC Apr. 4, 2006 and Aug. 28, 2006 Petitions in FERC Docket No. RM06-16-000.
33
See NERC Aug. 28 2006 Petition available at
http://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/FERC_Filing_Proposed_Reliabil
ity_Standards_Docket_RM06-16-000.pdf.
32

10

requirements were added. PRC-002-1 requires the Regional Reliability Organizations to
establish requirements for installation of Disturbance Monitoring Equipment and reporting of
Disturbance data to facilitate analyses of events and verify system models. PRC-018-1 is
designed to ensure that Disturbance Monitoring Equipment is installed and that Disturbance data
is reported in accordance with regional requirements to facilitate analyses of events.
In Order No. 693, the Commission identified Reliability Standard PRC-002-1 as a “fillin-the-blank” standard that should be modified to apply, through the Functional Model, to the
users, owners and operators of the Bulk-Power System that are responsible for providing
information. 34 As a result, the Commission decided not to approve or remand PRC-002-1. 35
The Commission agreed with various commenters to the Notice of Proposed Rulemaking
preceding Order No. 693 that greater continent-wide consistency could be achieved in this
Reliability Standard. 36 The Commission directed the ERO to consider the comments of the
American Public Power Association, Alcoa, Inc., and Otter Tail Power Company as it modifies
PRC-002-1 to provide missing information needed for the Commission to act on PRC-002. 37
These comments are provided in Exhibit E: Consideration of Issues and Directives. Generally,
the comments called for revisions to PRC-002-1 to provide greater consistency in this Reliability
Standard and a continent-wide approach.
In addition, the Commission approved PRC-018-1 as mandatory and enforceable. 38 In its
determination and in light of the approval status of PRC-002-1, the Commission stated
applicable entities were expected to comply with PRC-018-1, and the procedures specified in

34
35
36
37
38

Order No. 693 at PP 77-78.
Id. at P 1455.
Id. at P 1456.
Id.
Id. at P 1551.

11

PRC-002-1 would be provided pursuant to the data gathering provisions of the ERO’s Rules of
Procedure and the Commission’s ability to obtain information. 39
E.

History of Project 2007-11 Disturbance Monitoring

NERC initiated Project 2007-11 to address Commission concerns in Order No. 693,
specifically the “fill in the blank” aspects in both Reliability Standards PRC-002-1 and PRC018-1. A standard authorization request to initiate the project was initially posted in 2007 with a
scope of reviewing both standards and merging them into one replacement standard. In 2010,
the Standards Committee prioritized ongoing work, which resulted in moving Project 2007-11 to
informal development status. In its 2013 work plan, the Standards Committee changed the status
to “formal development” as part of the effort to address pending projects.
The standard drafting team revised the standard authorization request to focus the
standard on creating a results-based approach to the capture of data , instead of prescriptive
requirements on equipment necessary to capture the data. The standard drafting team also added
the Reliability Coordinator and Planning Coordinator as applicable entities in the standard
authorization request to allow the standard drafting team to assign responsibility for specifying
and collecting needed dynamic Disturbance data.
IV.

JUSTIFICATION FOR APPROVAL
As discussed in Exhibit D and below, the proposed Reliability Standard PRC-002-2,

satisfies the Commission’s criteria in Order No. 672 and is just, reasonable, not unduly
discriminatory or preferential, and in the public interest. Proposed PRC-002-2 contains the
Requirements necessary to facilitate the analysis of Disturbances on the Bulk-Power System.

39

Id. at P 1550.

12

The proposed Reliability Standard contains twelve Requirements, which collectively define what
SER, FR, and DDR data should be recorded and how it should be reported.
The following section broadly describes Disturbance monitoring, explains the purpose of
proposed Reliability Standard PRC-002-2, provides a description of and the technical basis for
the requirements, and describes how the proposed Reliability Standard improves reliability as
compared to prior versions. This section also provides a brief summary of how the proposed
Reliability Standards satisfies the outstanding Commission directives from Order No. 693 related
to PRC-002-1, fully implements Task Force Recommendation No. 28, and contributes to
NERC’s efforts to implement Task Force Recommendation No. 24. Finally, this section includes
a discussion of the enforceability of the proposed Reliability Standard.
A.

Disturbance Monitoring

The NERC Glossary defines a “Disturbance” as;
1. An unplanned event that produces an abnormal system
condition.
2. Any perturbation to the electric system.
3. The unexpected change in [Area Control Error] that is caused by
the sudden failure of generation or interruption of load. 40
It is important that Disturbances are monitored and analyzed so that the Bulk-Power System may
be planned and operated to avoid instability, separation and Cascading failures. As defined in
the NERC Glossary, Disturbance Monitoring Equipment consists of devices capable of
monitoring and recording system data pertaining to a Disturbance. 41 The definition includes
various types of recorders. Sequence of event recorders record equipment response to the event.

40

NERC Glossary at 30.
The definition also provides that “Phasor Measurement Units and any other equipment that meets the
functional requirements of DMEs may qualify as DMEs.”

41

13

This includes opening and closing of breakers and switches used to isolate faulted equipment.
Fault recorders record actual waveform data replicating the system primary voltages and
currents. This may include protective relays. Dynamic Disturbance recorders record incidents
that portray power system behavior during dynamic events such as low-frequency (0.1 Hz – 3
Hz) oscillations and abnormal frequency or voltage excursions.
Analysis of the data captured under the proposed Requirements of PRC-002-2 can be
used to improve the accuracy of planning and operating models and to identify risks to the BulkPower System that might not have been previously identified. DDR data is needed to compare
actual system performance with expected system performance under Disturbance conditions.
The results of the comparison of actual system performance with expected system performance
under Disturbance conditions allow engineers to improve system models that are used for both
planning and operating the Bulk-Power System. For example, current, voltage and frequency
waveforms for actual and expected system performance can be compared and revisions can be
made to the model to have the simulated waveforms more closely match the actual waveforms
under Disturbance conditions. These revised models result in more accurate planning studies
and, result in more accurate contingency analysis performed in near real-time.
B.

Proposed Reliability Standard PRC-002-2
1. Purpose of and Types of Data Covered in Proposed PRC-002-2

The purpose of proposed Reliability Standard PRC-002-2 is to have adequate data
available to facilitate analysis of Bulk Electric System Disturbances. The proposed Reliability
Standard focuses on ensuring that the requisite data is captured and the Requirements constitute a

14

results‐based approach to capturing data. 42 The proposed Reliability Standard consolidates the
current PRC-002-1 Reliability Standard and pertinent requirements of PRC-018-1 and improves
reliability by providing personnel with necessary data to enable more effective post event
analysis. The collected information can also be used to verify system models.
The proposed Reliability Standard includes coverage for SER, FR, and DDR data. SER
and FR data can be used for the analysis, reconstruction, and reporting of Disturbances.
Knowing the exact time of a breaker change of state and the waveforms of current, voltage and
frequency for individual circuits allows the precise reconstruction of events for both localized
and wide-area Disturbances. Analyses of wide-area Disturbances often begin by evaluation of
SER data to help determine the initiating event(s) and to follow the Disturbance propagation.
The recording of breaker operations helps to determine the interruption of line flows at a
particular bus. However, under the proposed Reliability Standard, SER and FR data is not
universally required since data from each bus is not necessary to be able to conduct an adequate
or thorough analysis of a Disturbance. FR data also augments SERs in evaluating circuit breaker
operation.
DDR data, which is also addressed in proposed PRC-002-2, is used to determine the
Bulk-Power System’s electromechanical transient and post-transient response and to validate
system model performance. DDR data location is typically based on studies which include
angular, frequency, voltage, and oscillation stability factors. However, to adequately monitor the
Bulk-Power System’s dynamic response and to ensure sufficient data to determine Bulk-Power
System performance, DDR data is required for key Elements in addition to a minimum

42

The original SAR for this proposed Reliability Standard was focused on requirements for the installation of
the equipment necessary to capture Disturbance monitoring data. The standard drafting team felt it was best to
describe the performance requirements (using a risk‐based approach) rather than prescribing necessary equipment.

15

requirement of DDR coverage based on an entity’s peak system demand. 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 generators during a Disturbance
helps the analysis of large Disturbances. DDR data shows transient response to Bulk-Power
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.
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 shortterm 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.
Entities responsible for the Requirements in proposed PRC-002-2 and an explanation of
each Requirement are included below. Additional technical support for each of these sections is
included in the Guidelines and Technical Basis Section of the proposed Reliability Standard in
Exhibit A.
2. Applicable Entities
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
16

4.3 Generator Owner
The proposed Reliability Standard applies to the Planning Coordinator or Reliability
Coordinator, as applicable in each Interconnection. In the Eastern Interconnection, the Planning
Coordinator is the responsible entity. In the Western Interconnection, the Reliability Coordinator
is the responsible entity. In ERCOT and the Quebec Interconnections, either the Planning
Coordinator or the Reliability Coordinator is the responsible entity. The proposed Reliability
Standard also applies to Transmission Owners and Generator Owners.
The Planning Coordinator or the Reliability Coordinator, as applicable, has the best widearea view of the Bulk Electric System and is most suited to be responsible for determining the
Bulk Electric System Elements for which dynamic DDR data is required. The Transmission
Owners and Generator Owners will have the responsibility for ensuring that adequate dynamic
Disturbance recording data is available for those Bulk Electric System Elements selected.
Bulk Electric System buses where SER and FR data is necessary 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 Bulk Electric System Elements on those buses will have the responsibility for ensuring that
adequate data is available.
3. Proposed Requirements
(1)

Requirement R1

R1. Each Transmission Owner shall: [Violation Risk Factor: Lower ] [Time Horizon:
Long- term 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
17

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.
Requirement R1 requires Transmission Owners to identify BES buses for which SER and
FR data is required, provide notification to other owners of BES Elements connected to those
particular BES buses that SER and FR data is necessary, and re-evaluate all BES buses every
five years. This information, taken collectively, will allow for analysis and reconstruction of
Bulk Electric System events.
Sequence of events and fault recording data for the analysis, reconstruction, and reporting
of Disturbances is important in order to be able to analyze the Disturbance. The exact time of a
breaker change of state and the waveforms of current, voltage and current for individual circuits
allows the precise reconstruction of events for both localized and wide-area Disturbances.
Analyses of wide-area Disturbances often begin by evaluation of SER data to help determine the
initiating event(s) and to follow the Disturbance propagation. The recording of breaker
operations helps to determine the interruption of line flows at a particular bus. As a general
principle, more quality data is better when performing Disturbance analysis. However, onehundred percent coverage of all Elements is not practical, cost-effective, nor required for
effective analysis of wide-area Disturbances. Selectivity in the required buses to monitor is
important to identify key buses with breakers where crucial information is available when
required to analyze a Disturbance. Selectivity will also avoid excessive overlap of coverage and
avoid gaps in critical coverage. The selection should provide coverage of Elements that could
propagate a Disturbance, but avoid mandating coverage of Elements that are more likely to be a

18

casualty of a Disturbance rather than a cause. The selection should ultimately establish selection
criteria to provide effective coverage in different regions of the continent.
Each Part of Requirement R1 is described separately below and identifies the
methodology designed by the standard drafting team for proper selection.
(a)

Part 1.1

Part 1.1 requires Transmission Owners to identify buses for which SER and FR data is
required. Transmission Owners are identified as the applicable entity in this Requirement
because Transmission Owners have the required tools, information, and working knowledge of
their systems to best determine buses where SER and FR data is required. The Requirement also
specifies a consistent methodology to identify those buses in Attachment 1: Methodology for
Selecting Buses for Capturing Sequence of Events Recording (SER) and Fault Recording (FR)
Data.
Analysis and reconstruction of Disturbances requires SER and FR data from key buses.
Attachment 1 provides a uniform methodology (Median Method) to identify those BES buses.
Review of actual short circuit data received from the industry in response to the drafting team’s
data request (June 5, 2013 through July 5, 2013) showed a strong correlation between the
available short circuit MVA at a transmission bus and its relative size and importance to the
Bulk-Power System based on (i) its voltage level, (ii) the number of Transmission Lines and
other Elements connected to the BES bus, and (iii) the number and size of generating units
connected to the bus. Buses with a large short circuit MVA level are Elements that have a
significant effect on System reliability and performance. Conversely, buses with very low short
circuit MVA levels seldom cause wide-area or Cascading Disturbances, so SER and FR data
from those Elements are not as significant for Disturbance analysis. After analyzing and
19

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.
Under proposed PRC-002-2, there are a minimum number of buses for which SER and
FR data is required based on the short circuit level. With the objective of having sufficient data
for Disturbance analysis, the drafting team 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 (see Step 8 discussion below). A description of how the standard
drafting team arrived at this approach is included in the Guidelines and Technical Basis of
Requirement R1 in the proposed Reliability Standard. The method employed is voltage level
independent, is likely to select buses near large generation centers, and is likely to select buses
where delayed clearing can cause Cascading. It also selects buses directly correlated to the
Universal Power Transfer equation, which means that lower line impedance leads to increased
power flows and greater system impact.
Attachment 1 provides a process for determining buses that require FR and SER data.
Attachment 1 also notes that, for this standard, a single 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. 43

43

See PRC-002-2, Attachment 1 at Step 1.

20

In Attachment 1, Transmission Owners are first required to determine a complete list of
buses that they own. Next, Transmission Owners reduce this list to only those BES buses that
have a maximum available calculated three phase short circuit MVA of 1,500 MVA or greater.
The standard drafting team chose the threshold MVA values based on engineering and
operational experience from analyzing and reviewing the short circuit data received from
industry in response to a data request issued during the standard development process. This
analysis showed a strong correlation between the available short circuit MVA at a transmission
bus and its relative size and importance to the Bulk-Power System. The correlation was based
on: (i) voltage level; (ii) the number of Transmission Lines and other Elements connected to the
bus; and (iii) the number and size of generating units connected to the bus. Buses with a large
short circuit MVA level significantly affect system reliability and performance, while buses with
very low short circuit MVA levels are not as significant. 44 As a result, the standard drafting
team included the narrowing of the buses covered by the standard based on the stated MVA
value in Attachment 1, Step 2.
In Step 3, Transmission Owners must determine the eleven BES buses on the list with the
highest maximum available calculated three phase short circuit MVA level. The standard
drafting team chose eleven BES buses because, in the judgment of the drafting team, a sufficient
number of buses is necessary to accomplish the data coverage being sought for Disturbance
analysis. Because the methodology stipulated the use of the median or middle value, eleven is
used to provide five buses above and five buses below the median. In Step 4, Transmission
Owners calculate the median MVA level of the eleven BES buses from Step 3, and in Step 5,
determine a value that is twenty percent of this median MVA level from Step 4. The purpose of

44

BES buses with very low short circuit MVA levels seldom cause wide-area or Cascading System
Disturbances.

21

this calculation is to provide a more narrowed scope for larger Transmission Owners that might
have a large number of buses with a three-phase short circuit MVA level at 1500 MVA or above.
This limits the number of buses for FR and SER data required under the standard for such
entities while still providing adequate data for Disturbance analysis.
Step 6 again requires Transmission Owners to reduce the list to only those that have a
maximum available calculated three-phase short circuit MVA higher than the greater of either
1,500 MVA or twenty percent of the median MVA level determined in Step 5.
Finally, Step 7 begins to identify the necessary buses. If there are no buses on the list by
Step 7, the procedure is complete and no FR and SER data will be required. If the list has one or
more but less than or equal to eleven buses, FR and SER data is required at the bus with the
highest maximum available calculated three phase short circuit MVA as determined in Step 3. If
the list has more than eleven BES buses, SER and FR data is required on at least 10 percent of
the BES buses determined in Step 6 with the highest maximum available calculated three-phase
short circuit MVA.
To assure that adequate numbers of buses are included for collection of SER and FR data,
Step 8 requires SER and FR data at additional buses from the list determined in Step 6. The
aggregate of the number of buses determined in Step 7 and buses included through Step 8 must
be at least twenty percent of the BES buses determined in Step 6. The remaining locations
needed to meet this test are selected at the Transmission Owner’s discretion to provide maximum
wide-area coverage for SER and FR data based on each Transmission Owner’s unique System
configuration. Attachment 1 recommends the following BES bus locations:
•
•
•
•

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;
22

•
•

BES buses with reactive power devices; and
Major Facilities interconnecting outside the Transmission Owner’s area.

These locations are derived from PRC-002-1 and were reviewed and confirmed for inclusion by
the standard drafting team as valuable information to inform the selection of locations.
Step 9 finally explains that the applicable buses subject to Requirement R1 is the
collective total from Steps 7 and 8.
(b)

Part 1.2

Part 1.2 requires Transmission Owners to notify other owners of Elements connected to
those buses, if any, within 90-calendar days of completion of Part 1.1, that those Elements
require SER data and/or FR data. Notification is necessary because these buses may be owned
by more than one entity. The ninety calendar-day notification period gives the Transmission
Owners adequate time to make appropriate determinations and notifications.
(c)

Part 1.3

Part 1.3 requires each Transmission Owner to re-evaluate the bus list by repeating the
performance in Parts 1.1 and Parts 1.2 at least every five (5) calendar years to account for system
changes. The standard drafting team determined that the five (5) calendar year re-evaluation of
the list of identified Elements is a reasonable interval based on its experience with changes to
the Bulk-Power System that may affect SER and FR data requirements.
(2)

Requirement R2

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]

23

Requirement R2 is intended to capture SER data for the status (open/close) of the circuit
breakers that can interrupt the current flow through each Element connected to a bus identified in
Requirement R1. Analyses of wide-area Disturbances often begin by evaluation of SERs to help
determine the initiating Disturbance(s) and follow the Disturbance propagation throughout the
Bulk-Power System. Recording of breaker operations helps to determine a timeline for status
changes in circuit breaker positioning during a Disturbance. Generator Owners are included in
this Requirement because a Generator Owner may, in some instances, own breakers directly
connected to the Transmission Owner’s bus. Each breaker status change will be time stamped
according to Requirement R10 to a time-synchronized clock.
(3)

Requirement R3

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.
Requirement R3 requires the Transmission Owner and Generator to have FR data to
determine certain electrical quantities. In order to cover all possible fault types, all bus phase-toneutral voltages are required to be determinable for each bus identified in Requirement R1. The
required electrical quantities may be either directly measured or determinable if sufficient FR
data is captured. 45 For Disturbance analysis, bus voltage data is sufficient. To distinguish
between phase faults and ground faults, phase and residual currents are required. Furthermore, it

45

E.g. residual or neutral current if the phase currents are directly measured.

24

allows Transmission Owners and Generator Owners to determine the location of the fault and the
cause of relay operation(s).
For transformers operating with a low-side voltage of 100kV or above, the required data
can come from either the high-side or low-side of the transformer. However, generator step-up
transformers (“GSUs”) and the leads connecting the GSU transformer(s) to the Transmission
System that exclusively export energy directly from a generating unit or plant are excluded from
Requirement R3 because the FR data on the transmission system captures the faults on the
generator interconnection. The Generator Owners may install the FR data capability or contract
with the Transmission Owners that already have suitable FR data for the provision of the data to
determine the required electrical quantities.
(4)

Requirement R4

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 post- trigger 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.
Requirement R4 provides for time stamped pre- and post- trigger fault data that aids in
analyzing system performance during fault conditions and determining whether the performance
was as intended. System faults generally last for a short time period and having a 30-cycle total

25

minimum record length is adequate to capture such data. The requirement allows an entity to
provide multiple records. This allows time-synchronized legacy microprocessor relays to meet
the requirement when the equipment is not capable of providing fault data in a single record of
30-contiguous cycles. Moreover, the minimum recording rate must be 16 samples per cycle (960
Hz) to get sufficient point and wave data for recreating accurate fault conditions.
(5)

Requirement R5

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.
26

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.
Requirement R5 provides that each Responsible Entity will have DDR data for one
Element and at least one additional Element per 3,000 MW of its historical simultaneous peak
system demand. Furthermore, Requirement R5 ensures that there is adequate wide-area
coverage of DDR data for specific Elements to facilitate accurate and efficient Disturbance
analysis. Monitoring the Elements required for DDR data will facilitate thorough and
informative Disturbance analysis of wide-area Disturbances on the Bulk-Power System. 46
Ensuring that data for these Elements is captured significantly improves the accuracy of
the analysis and understanding of why a Disturbance occurred, not simply what occurred. DDR
plays a critical role in wide-area Disturbance analysis as it is used for capturing the transient and
post-transient response. Such data is used for Disturbance analysis and for validating BulkPower System performance. Each Responsible Entity (Reliability Coordinator or Planning
Coordinator) must ensure that there are sufficient Elements identified for DDR data capture
because they have the best wide-area view of the system. Identifying the Elements requiring
DDR data per Requirement R5 is based on industry experience with wide area Disturbance
analysis and the need for adequate data to facilitate Disturbance analysis.
The standard drafting team decided that the five (5) calendar year re-evaluation of the list
of identified Elements is a reasonable interval based on its experience with changes to the BulkPower System that may affect DDR data requirements. However, this standard does not
preclude the Responsible Entity from performing this re-evaluation more frequently to capture

46

Refer to the Guidelines and Technical Basis Section for more detail on the rationale and technical
reasoning for each identified Element in Requirement R5, part 5.1. Part 5.2 ensures wide-area coverage across all
Responsible Entities.

27

updated Elements. Changes to the bulk power system do not mandate immediate inclusion of
Elements into the in-force list, but the Elements must be re-evaluated at least every five (5)
calendar years per Requirement R5, Part 5.4.
The Transmission Owners and Generator Owners whose Elements were selected must be
notified to ensure that each Owner is aware of its responsibilities. The Responsible Entities
(Planning Coordinator or Reliability Coordinator as applicable) must notify all Owners of the
selected Elements that DDR data is required when requested per Requirement R5, Part 5.3.
However, notification must only include the list of selected Elements that each Transmission
Owner and Generator Owner respectively owns and not the entire list. Furthermore, the
Responsible Entities must include the specific data for each Element in the notification. 47
Each Transmission and Generator Owner is responsible for the provision of data for the
Elements identified in Requirement R5 and subject to the conditions specified in Requirements
R6-R11. The Implementation Plan allows each Transmission Owner and Generator owner to
phase-in the data provision Requirements of the proposed Reliability Standard.
DDR data is only required for one end or terminal of the Elements that were selected,
except for high-voltage, direct current circuits. 48 For an interconnection between two
Responsible Entities, each must consider this interconnection independently and work together to
determine how to monitor the Elements requiring DDR data. For an interconnection between
two Transmission Owners or a Transmission Owner and a Generator Owner, the Responsible
Entity must determine which entity will provide the DDR data and respectively notify the owners
of such determination.

47

This data can either be directly measured or accurately calculated.
For example, DDR data must be provided for at least one terminal of a Transmission Line or GSU
transformer, but not both terminals.

48

28

(6)

Requirement R6

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.
Requirement R6 allows the Transmission Owner to determine (calculate, derive, etc.) the
electrical quantities specified in Parts 6.1-6.4 for Disturbance analysis. DDR is used to measure
transient response to system Disturbances during a relatively balanced post-fault condition.
Providing a phase-to-neutral voltage or positive sequence voltage is sufficient to measure the
transient response. Furthermore, since all of the buses within a particular location are at the
same frequency, one frequency measurement is adequate. 49
(7)

Requirement R7

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
49

The data requirements for proposed PRC-002-2 are based on a System configuration assuming that all
normally closed circuit breakers on a BES bus are closed.

29

measurements are required.
7.4 Frequency of at least one of the voltages in Requirement R7,
Part 7.1.
Requirement R7 ensures that generator data is available to determine the electrical
quantities specified in Parts 7.1-7.4. A crucial part of wide-area Disturbance analysis is
understanding the dynamic response of generating resources. Requiring Generator Owners to
have DDR data at either the high or low-side of the GSU to determine the specified electrical
quantities to adequately capture generator responses is necessary for the analysis of a
Disturbance. Each Generator Owner is responsible for providing the necessary DDR data and
may contract with the Transmission Owners that already have suitable DDR data for provision of
such data.
(8)

Requirement R8

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 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 Eastern Interconnection
o Western Interconnection
o ERCOT Interconnection
o 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 Eastern Interconnection
o Western Interconnection
o ERCOT Interconnection

< -0.03125 Hz/sec
< -0.05625 Hz/sec
< -0.08125 Hz/sec
30

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

o Hydro-Quebec
Interconnection

< -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.
Requirement R8 ensures that DDR data is available on a continuous basis so that pre- and
post-contingency timeframes can be analyzed. This continuous recording of data allows analysis
for the evolving sequence of events that occur over an extended period of time, which may lead to
large-scale system outages. DDR data is essential to this analysis process. Providing available
data pre and post-contingency helps identify the causes and effects of each event leading to the
outages. Continuously recording and storing such data is necessary to ensure that sufficient data
is available for the entire Disturbance. Legacy DDR data recording equipment may not have the
capability to record continuously. Therefore, to accommodate its use for the purpose of this
standard, triggered records that meet the criteria of Parts 8.1 and 8.2 are acceptable if the
equipment is installed prior to proposed PRC-002-2’s effective date.50
(9)

Requirement R9

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.
Requirement R9 ensures consistency in DDR data sampling rates as well as the output
recording rate. Using an input sampling rate of at least 960 samples per second (which

50

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.

31

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.
Moreover, using an output rate recording rate of electrical quantities of at least 30 times per
second provides these adequate recording speeds 51 to monitor low frequency oscillations during
a Disturbance.
(10)

Requirement R10

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.
Requirement R10 ensures time synchronization of large volumes of geographically
dispersed records from diverse recording sources critical to Disturbance monitoring. SER, FR
and DDR data are required to be time-synchronized using the Coordinated Universal Time
(“UTC”) standard and formatted either with or without local time offsets. 52 The accuracy of the
time synchronization applies only to the clock used by the monitoring equipment. 53 However,
the time synchronization of the data itself is not required because of the inherent delays
associated with measuring the electrical quantities (data) and events such as breaker closing,
measurement transport delays, algorithm and measurement calculation techniques, etc.

51

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.
52
UTC is a recognized time standard that uses atomic clocks for generating precision time measurements.
Local time offsets are expressed as a negative number (i.e. the difference between UTC and the local time zone
where the measurements are recorded).
53
The equipment used to measure the electrical quantities (FR, SER and DDR data) must be time
synchronized to ± 2m/s accuracy.

32

Therefore, ensuring that the monitoring devices’ internal clocks are within ± 2m/s accuracy is
sufficient for time-synchronized data.
(11)

Requirement R11

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.
Requirement R11 standardizes formatting and naming of wide-area Disturbance data that
significantly improves timely analysis. 54 Requirement R11 further provides for a reasonable
time-period (30 calendar days) to collect data and perform any necessary calculations or
formatting. Additionally, Requirement R11 provides for a practical time limit (10 calendar days)
on the amount of time data must be stored and informs the requesting entities how long the data
will be available. Retaining the data for any longer than 10 calendar days would be expensive
and unnecessary. Any SER data recorded must be stored in simple ASCII.CSV format because

54

Note that wide-area Disturbance analysis includes data recording from many devices and entities.

33

it will significantly improve data analysis for event records and enable using software tools to
analyze SER data. 55 Part 11.4 provides for a well-established industry-standard formatting of FR
and DDR data files, 56 while Part 11.5’s standardized naming format provides for a streamlined
analysis of large Disturbances, and includes critical records such as local time offset associated
with the synchronization of the data. 57
(12)

Requirement R12

R12. Each Transmission Owner and Generator Owner shall, within 90calendar 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.

Requirement R12 ensures that all Transmission Owners and Generator Owners who own
equipment used in collecting the required data have the ability to correct any failures and ensure
the data is available for Disturbance analysis. However, an outage of the monitored Element
does not constitute a failure of the Disturbance monitoring recording capability. Each
Transmission and Generator Owner must restore recording capability within ninety calendar
days. In the event the repairs cannot be made within 90 calendar days, the entity must develop a
Corrective Action Plan (“CAP”) for restoring the data recording capability. 58 The CAP timeline
depends on the entity and type of data required.

55

ASCII.CSV format is outlined in Attachment 2. Either equipment can provide the data in this format or a
simple conversion program can be used to convert files into this format.
56
Part 11.4 provides standard format IEEE c37.111, which is the IEEE Standard for Common Format for
Transient Exchange (COMTRADE) revision 1999 or later.
57
Part 11.5 uses the standardized naming format, C37.232-2011, IEEE Standard for Common Format for
Naming Time Sequence Data Files (COMNAME), used for providing Disturbance monitoring data.
58
An entity may not be able to restore the data recording capability for a variety of reasons, such as budget
cycle, service crew availability, vendor availability, needing to order parts or equipment, needed outages, etc.

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4. Improvements and Consideration of Commission Directives
Proposed PRC-002-2 improves upon Reliability Standards PRC-002-1 and PRC-018-1.
Proposed PRC-002-2 creates a single, consolidated Disturbance monitoring Reliability Standard.
Proposed PRC-002-2 also includes revisions to remove “fill-in-the-blank” aspects in both
Reliability Standards in response to Order No. 693. The proposed Reliability Standard is no
longer dependent on regional criteria to provide appropriate data. This creates greater
consistently in the data recordation and will allow for data to be compared across the continent
during analysis of Bulk-Power System Disturbances. The proposed Reliability Standard also
provides a consistent, continent-wide approach to determining what data must be recorded for
analysis of Disturbances in response to the Commission’s determinations and commenter
suggestions in Order No. 693.
The emphasis in proposed PRC-002-2 has shifted from the prior Reliability Standards to
reflect what Bulk Electric System data is captured rather than on the method for how
Disturbance monitoring data is captured. There are a variety of ways to capture the data
proposed PRC-002-2 addresses, and existing and currently available equipment can meet the
Requirements of this standard. As a result, the proposed Reliability Standard improves data
capturing practices while providing efficiency in the approach taken by utilizing existing
methods for data collection. PRC-002-2 also addresses the importance of addressing the
availability of Disturbance monitoring capability to ensure the completeness of data capture.
In some instances, the Requirements of the proposed Reliability Standard are prescriptive
in their nature. For example, Requirement R10 specifies a time synchronization requirement of
± 2m/s accuracy and the use of UTC. Task Force Recommendation No. 28 specifically called
for a requirement to have time-synchronized data. In order to meet this Recommendation,

35

Requirement R10 was developed to ensure that both existing and future installations of recording
capability could meet the time synchronization requirement. Other instances of prescriptive
Requirements are necessary to ensure that the intent of Recommendation No. 28 is realized. The
Recommendation also stated:
The Task Force supports the intent of this requirement strongly, but
it recommends a broader approach:
A. FERC and appropriate authorities in Canada should require the
use of data recorders synchronized by signals from the Global
Positioning System (GPS) on all categories of facilities whose data
may be needed to investigate future system Disturbances, outages,
or blackouts.
B. NERC, reliability coordinators, control areas, and transmission
owners should determine where high speed power system
Disturbance recorders are needed on the system, and ensure that
they are installed by December 31, 2004.
C. NERC should establish data recording protocols.
The standard drafting team took these recommendations into consideration when
developing the proposed Reliability Standard. Specific data recording protocols were included
to address the concerns stated in the Final Blackout Report including the importance of having
time-synchronized system data recorders. As noted in the Final Blackout Report, “the Task
Force’s investigators labored over thousands of data items to determine the sequence of events,
much like putting together small pieces of a very large puzzle.” 59 This process could have been
significantly faster and easier if there had been wider use of synchronized data recording devices.
In summary, Commission approval of this proposed Reliability Standard will meet the
Commission directives in Order No. 693 and complete work to implement multiple
Recommendations from the both the NERC Board and the Task Force. It will also improve

59

Final Blackout Report at 162.

36

analysis and modeling of Disturbances to assist in preventing future Disturbances in support of
Task Force Recommendation No. 24 by including a version of PRC-002 in the NERC Reliability
Standards that is mandatory and enforceable.
C.

Enforceability of Proposed Reliability Standard

The proposed Reliability Standard PRC-002-2 includes Measures that support each
Requirement to help ensure that the Requirements will be enforced in a clear, consistent, nonpreferential manner and without prejudice to any party. The proposed Reliability Standard also
includes VRFs and VSLs for each Requirement. The VRFs and VSLs for the proposed
Reliability Standard comport with NERC and Commission guidelines related to their assignment.
A detailed analysis of the assignment of VRFs and the VSLs for proposed PRC-002-2 is
included as Exhibit F.
V.

CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve:
•

the proposed Reliability Standard in Exhibit A;

•

the other associated elements in the Reliability Standard in Exhibit A including the VRFs
and VSLs (Exhibits A and F); and

•

the Implementation Plan, including the noted retirements, included in Exhibit B.

Respectfully submitted,
/s/ William H. Edwards

37

Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Associate General Counsel
William H. Edwards
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]
[email protected]

Counsel for the North American Electric
Reliability Corporation
Date: December 15, 2014

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