NERC Petition

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION

)
)

Docket No.

PETITION FOR APPROVAL OF
FIVE PROPOSED RELIABILITY STANDARDS
MOD-025-2, MOD-026-1, MOD-027-1, PRC-019-1 AND PRC-024-1

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
Assistant General Counsel
Stacey Tyrewala
Senior 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 North American Electric Reliability
Corporation

May 30, 2013

TABLE OF CONTENTS
I. Executive Summary…………………………………………………………………………..

2

A. Modeling, Data and Analysis Standards: MOD-025-2, MOD-026-1 and MOD-027-1…… 3
B. Protection and Control Standards: PRC-019-1 and PRC-024-1…………………………… 5
II. Notices and Communications………………………………………………………………... 6
III. Background …………………………………………………………………………………. 6
A. Regulatory Framework and NERC Reliability Standards Development Procedure………. 6

IV. Justification for Approval of the Proposed Reliability Standards………………………… 8
A. MOD-025-2 – Verification and Data Reporting of Generator Real and Reactive Power
Capability and Synchronous Condenser Reactive Power Capability………………………. 8
1. Merger of MOD-024-1 and MOD-025-1……………………………………… 9
2. Commission Directives……………………………………………………….. 10
B. MOD-026-1 – Verification of Models and Data for Generator Excitation Control System or
Plan Volt/Var Functions……………………………………………………………………. 13
C. MOD-027-1 – Verification of Models and Data for Turbine/Governor and Load Control or
Active Power/Frequency Control Functions………………………………………………. 18
D. PRC-019-1 – Coordination of Generating Unit or Plant Capabilities, Voltage Regulating
Controls, and Protection……………………………………………………………………..22
E. PRC-024-1 – Generator Frequency and Voltage Protective Relay Settings………………. 25
1. Commission Directives……………………………………………………… 26
F. Enforceability of the Proposed Reliability Standards…………………………………….. 31
V. Conclusion……………………………………………………………………………………. 32
Exhibit A — Proposed Reliability Standards Submitted for Approval
Exhibit B — Implementation Plan for Reliability Standards Submitted for Approval
Exhibit C —Order No. 672 Criteria
Exhibit D — Analysis of how VRFs and VSLs Were Determined Using Commission Guidelines
Exhibit E — Summary of the Reliability Standard Development Proceeding and Complete Record
of Development of Proposed Reliability Standard
Exhibit F — Standard Drafting Team Roster for NERC Standards Development Project 2007-09

i

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION

)
)

Docket No.

PETITION FOR APPROVAL OF
FIVE PROPOSED RELIABILITY STANDARDS
MOD-025-2, MOD-026-1, MOD-027-1, PRC-019-1 AND PRC-024-1
The North American Electric Reliability Corporation (“NERC”) 1 hereby requests the
Federal Energy Regulatory Commission (“FERC” or the “Commission”) approve, in accordance
with Section 215(d)(1) of the Federal Power Act (“FPA”) 2 and Section 39.5 of the Commission’s
regulations, 18 C.F.R. § 39.5 (2012), five proposed Reliability Standards which were approved
by the NERC Board of Trustees on February 7, 2013 and May 9, 2013: 3

1

•

MOD-025-2—Verification and Data Reporting of Generator Real and Reactive
Power Capability and Synchronous Condenser Reactive Power Capability;

•

MOD-026-1—Verification of Models and Data for Generator Excitation Control
System or Plant Volt/Var Control Functions;

•

MOD-027-1—Verification of Models and Data for Turbine/Governor and Load
Control or Active Power/Frequency Control Functions;

•

PRC-019-1—Coordination of Generating Unit or Plant Capabilities, Voltage
Regulating Controls, and Protection; and

•

PRC-024-1—Generator Frequency and Voltage Protective Relay Settings.

NERC has been certified by the Commission as the electric reliability organization (“ERO”) in accordance
with Section 215 of the Federal Power Act. The Commission certified NERC as the ERO in its order issued July 20,
2006 in Docket No. RR06-1-000. North American Electric Reliability Corp., 116 FERC ¶ 61,062 (2006) (“ERO
Certification Order”).
2
16 U.S.C. § 824o (2012).
3
MOD-025-2, MOD-026-1, MOD-027-1 and PRC-019-1 were approved by the NERC Board of Trustees on
February 7, 2013 and PRC-024-1 was approved on May 9, 2013. Unless otherwise designated, all capitalized terms
shall have the meaning set forth in the Glossary of Terms Used in NERC Reliability Standards, available here:
http://www.nerc.com/files/Glossary_of_Terms.pdf.

NERC is hereby requesting approval of the proposed Reliability Standards, the associated
implementation plans, Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”),
and retirement of MOD-024-1 – Verification of Generator Gross and Net Real Power Capability
and MOD-025-1 – Verification of Generator Gross and Net Reactive Power Capability prior to
the effective date of MOD-025-2.

I.

EXECUTIVE SUMMARY
The purpose of Project 2007-09, Generator Verification and the proposed Reliability

Standards included herein is to ensure (i) that generators will not trip off-line during specified
voltage and frequency excursions 4 or as a result of improper coordination between generator
protective relays and generator voltage regulator controls and limit functions (such coordination
will include the generating unit’s capabilities), and (ii) that generator models accurately reflect
the generator’s capabilities and operating characteristics. Four of the five proposed Reliability
Standards are new. Existing Reliability Standards MOD-024-1 and MOD-025-1 were combined
into a single proposed Reliability Standard, MOD-025-2. Together, these five proposed
Reliability Standards address generator verifications needed to support Bulk-Power System
reliability and will ensure that accurate data is verified and made available for planning
simulations.
Good quality simulation models of power system equipment are beneficial to the
reliability of the Bulk-Power System. Model validation ensures the proper performance of the
control systems and validates the computer models used for stability analysis. In addition to
obtaining model data, the tests performed to gather this information may uncover latent defects

4

System frequency reflects the instantaneous balance between generation and load. Reliable operation of a
power system depends on maintaining frequency within predetermined boundaries above and below a scheduled
value, which is 60 Hertz (“Hz”) in North America.

2

that could lead to inappropriate unit response during system disturbances, thereby improving the
reliability of the unit and the power system.
Power system planning and operational studies require the simulation of the response of
synchronous machines and their respective control systems. For these studies, it is essential that
the control systems of the synchronous machines be modeled in sufficient detail. 5 The desired
models must be suitable for representing the actual equipment performance for large, severe
disturbances as well as for small perturbations. To obtain accurate simulation, not only must the
models contain an adequate level of detail, but the values of the parameters in the models must
also correspond to actual field values. The equipment to be tested and modeled includes the
generator and its control systems, 6 excitation systems, 7 power system stabilizers and turbine
governors. 8 Protective relay coordination with equipment capabilities and control system
limiters is equally important. 9 Collectively, these five proposed Reliability Standards address
generator verifications needed to support Bulk-Power System reliability.
A. Modeling, Data and Analysis Standards: MOD-025-2, MOD-026-1 and MOD027-1
The Modeling, Data and Analysis (“MOD”) body of Reliability Standards ensure that
power system models accurately reflect the generator’s capabilities and operating characteristics
of the power system elements. The models are used in operating and planning studies. The
MOD Standards are intended to standardize methodologies and system data needed for

5

See IEEE Task Force on Generator Model Validation Testing of the Power System Stability Subcommittee,
“Guidelines for Generator Stability Model Validation Testing,” IEEE PES General Meeting 2007, paper
07GM1307.
6
This equipment is addressed in proposed Reliability Standard MOD-25-2.
7
The primary function of the excitation system is to regulate voltage and thereby control var flow in the
system.
8
This equipment is addressed in proposed Reliability Standards MOD-026-1 and MOD-027-1.
9
This equipment is addressed in proposed Reliability Standards PRC-019-1 and PRC-024-1.

3

traditional transmission system operation and expansion planning, reliability assessment and the
calculation of available transfer capability in an open access environment.
Proposed Reliability Standard MOD-025-2 requires verification of Real and Reactive
Power of applicable generator and synchronous condenser facilities. The standard drafting team
removed the fill-in-the-blank components of the version 1 standards (MOD-024-1 and MOD025-1) and provided for explicit verification requirements in the proposed MOD-025-2 Standard.
This proposed Reliability Standard ensures that accurate information on generator gross and net
Real and Reactive Power capability and synchronous condenser Reactive Power capability is
available for planning models used to assess Bulk Electric System (“BES”) reliability.
Proposed Reliability Standard MOD-026-1 relates to the generator excitation control
system or the plant volt/var control functions. The Generator Owner is required to provide a
verified model to the Transmission Planner according to the periodicity specified in the standard.
The purpose is to verify that the generator excitation control system or plant volt/var control
function model and the model parameters used in dynamic simulations 10 performed by the
Transmission Planner accurately represent the generator excitation control system or plant
volt/var control function behavior when assessing BES reliability.
Proposed Reliability Standard MOD-027-1 relates to the generating unit turbine/governor
and load control 11 or active power/frequency control functions. 12 The Generator Owner is
required to provide a verified model to the Transmission Planner according to the periodicity
specified in the standard. The purpose is to verify that the turbine/governor and load control or
10

Dynamic simulations simulate real-life reactions whereas static simulations only take a snapshot in time.
Dynamic simulations are intended to show how the power system will react over time to certain events. The models
for dynamic simulations are more complicated and involve voltage and frequency response characteristics over a
fixed time period. Each event on the grid causes voltages and/or frequency to change. Dynamic simulations are
designed to predict these changes.
11
Turbine/governor and load control applies to conventional synchronous generation.
12
Active power/frequency control applies to inverter connected generators (often found at variable energy
plants).

4

active power/frequency control model and the model parameters, used in dynamic simulations
performed by the Transmission Planner that assess BES reliability, accurately represent
generator unit real power response to system frequency variations. 13
B. Protection and Control Standards: PRC-019-1 and PRC-024-1
The Protection and Control (“PRC”) body of Reliability Standards apply to Transmission
Operators, Transmission Owners, Generator Operators, Generator Owners, Distribution
Providers and Regional Reliability Organizations and cover a wide range of topics related to the
protection and control of power systems. Protection and control systems on Bulk-Power System
elements are an integral part of reliable grid operation. Protection systems are designed to detect
and isolate faulty elements on a system, thereby limiting the severity and spread of system
disturbances, and preventing possible damage to protected elements. The function, settings, and
limitations of a protection system are critical in establishing System Operating Limits and
Interconnection Reliability Operating Limits.
Proposed Reliability Standard PRC-019-1 is a protection Standard that requires the
Generator Owner and Transmission Owner 14 to coordinate the voltage regulating system controls
with the equipment capabilities and settings of Protection System devices and functions.
Proposed Reliability Standard PRC-024-1 contains requirements for generator protection
system performance during frequency and voltage excursions. The proposed Reliability
Standard ensures that generating units are not tripped by their protective relays and remain
connected during specified frequency and voltage excursions and ensures expected generating

13

The proposed implementation plans for MOD-026-1 and MOD-027-1 are of a longer duration due to the
complexity of the tasks involved as explained in Exhibit C.
14
Only applicable to Transmission Owners that own synchronous condenser(s). See PRC-019-1, Section
4.1.2.

5

unit performance during frequency and voltage excursions is communicated to Planning
Coordinators and Transmission Planners for accurate system modeling.

II.

NOTICES AND COMMUNICATIONS

Notices and communications with respect to this filing may be addressed to the following: 15
Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Assistant General Counsel
Stacey Tyrewala*
Senior 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]

Mark Lauby
Vice President and Director of Standards
Laura Hussey
Director of Standards Development
North American Electric Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595– facsimile

III.

BACKGROUND
A. Regulatory Framework and NERC Reliability Standards Development
Procedure
By enacting the Energy Policy Act of 2005, 16 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 duty of certifying an ERO that would be charged with developing and
enforcing mandatory Reliability Standards, subject to Commission approval. Section 215 of the

15

Persons to be included on the Commission’s service list are indicated with an asterisk. NERC requests
waiver of 18 C.F.R. § 385.203(b) to permit the inclusion of more than two people on the service list.
16
16 U.S.C. § 824o (2012).

6

FPA states that all users, owners, and operators of the Bulk-Power System in the United States
will be subject to Commission-approved Reliability Standards. 17
Section 215(d)(5) of the FPA authorizes the Commission to order the ERO to submit a
new or modified Reliability Standard. Pursuant to Section 215(d)(2) of the FPA and Section
39.5(c)(1) 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. In Order
No. 693, the Commission noted that it would defer to the “technical expertise” of the ERO with
respect to the content of a Reliability Standard and explained that, through the use of directives,
it provides guidance but does not dictate an outcome. Rather, the Commission will consider an
equivalent alternative approach provided that the ERO demonstrates that the alternative will
address the Commission’s underlying concern or goal as efficiently and effectively as the
Commission’s proposal, example, or directive. 18
Section 39.5(a) of the Commission’s regulations requires the ERO to file with the
Commission for its approval each Reliability Standard that the ERO proposes to become
mandatory and enforceable in the United States, and each modification to a Reliability Standard
that the ERO proposes to be made effective. The Commission has the regulatory responsibility
to approve standards that protect the reliability of the Bulk-Power System and to ensure that such
standards are just, reasonable, not unduly discriminatory or preferential, and in the public
interest.

17

See Section 215(b)(1)(“All users, owners and operators of the bulk-power system shall comply with
reliability standards that take effect under this section.”).
18
See Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶
31,242 at PP 31, 186-187, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).

7

The proposed Reliability Standards were developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process. 19 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of its Rules of Procedure and the NERC Standard Processes Manual. 20 In its ERO
Certification Order, 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 and thus satisfies certain of the criteria for approving Reliability
Standards. The development process is open to any person or entity with a legitimate interest in
the reliability of the Bulk-Power System. NERC considers the comments of all stakeholders, and
a vote of stakeholders and the NERC Board of Trustees is required to approve a Reliability
Standard before the Reliability Standard is submitted to the Commission for approval.

IV.

JUSTIFICATION FOR APPROVAL OF PROPOSED RELIABILITY
STANDARDS
Provided below is the following: (A) a description of each proposed Reliability Standard

and discussion of how applicable Commission directives are satisfied; and (B) justification for
the proposed Reliability Standards on a Requirement by Requirement basis.
A. MOD-025-2 -- Verification and Data Reporting of Generator Real and Reactive
Power Capability and Synchronous Condenser Reactive Power Capability

19

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.”).
20
The NERC Rules of Procedure are available here: http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The current NERC Standard Processes Manual is available here:
http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf.

8

Proposed Reliability Standard MOD-025-2 consists of three Requirements and two
Attachments. The proposed Reliability Standard is a result of merging two existing Reliability
Standards, MOD-024-1 and MOD-025-1, into a single standard and is applicable to Generator
Owners and Transmission Owners that own synchronous condenser(s). Attachment 1 is
incorporated into all three Requirements (R1.1, R2.1 and R3.1) and specifies: (1) the frequency
with which a new verification must be conducted of generator Real and Reactive Power
capability and synchronous condenser Reactive Power capability; and (2) the specifications for
applicable Facilities, including a requirement to record data for the verifications. Attachment 2
is incorporated into all three Requirements (R1.2, R2.2, and R3.2) and is to be used to report the
information identified in Attachment 1. 21
1. Merger of MOD-024-1 and MOD-025-1
Existing Reliability Standard MOD-024-1, Verification of Generator Gross and Net Real
Power Capability, is a fill-in-the-blank standard and requires the regional reliability organization
to establish and maintain procedures to address verification of generator gross and net real power
capability. It also requires a generator owner to follow its regional reliability organization’s
procedure for verifying and reporting gross and net real power generating capability. 22
Existing Reliability Standard MOD-025-1 is also a fill-in-the-blank standard and requires the
regional reliability organization to establish and maintain procedures to address verification of
generator gross and net reactive power capability. 23

21

Note, if the configuration of the applicable Facility does not lend itself to the use of the diagram, tables or
summaries for reporting the required information, changes may be made to the form, provided that all required
information is reported.
22
The Commission neither approved nor remanded MOD-024-1 in Order No. 693 and instead directed NERC
to submit additional information.
23
Existing Reliability Standard MOD-025-1 requires the regional reliability organization to provide its
generator gross and net reactive power capability verification and reporting procedures, and any changes to those
procedures, to the generator owners, generator operators, transmission operators, planning authorities and
transmission planners affected by the procedure within 30 calendar days of approval of the Reliability Standard.

9

Existing Reliability Standards MOD-024-1 and MOD-025-1 have been combined into a
single proposed Reliability Standard, MOD-025-2, that requires verification of Real and
Reactive Power of applicable generator and synchronous condenser facilities. The fill-in-theblank components of the version 1 standards have been removed from proposed Reliability
Standard, MOD-025-2, and the Standard contains explicit verification requirements. This
proposed Standard ensures that accurate information on generator gross and net Real and
Reactive Power capability and synchronous condenser Reactive Power capability is available for
planning models used to assess BES reliability.
2. Commission Directives
The Commission issued three directives with respect to MOD-024-1 and MOD-025-1
that are resolved by proposed Reliability Standard MOD-025-2: (1) the Commission expressed a
concern in Order No. 693 (at P 1311) that Requirement R2 of MOD-024-1, which specifies that
the “regional reliability organization shall provide generator gross and net real power capability
verification within 30 calendar days of approval,” is not clear; 24 (2) the Commission directed
NERC to “develop appropriate requirements to document test conditions and the relationships
between test conditions and generator output so that the amount of power that can be expected to
be delivered from a generator at different conditions, such as peak summer conditions, can be

Like MOD-024-1, the Commission neither approved nor remanded MOD-025-1 in Order No. 693 and instead
directed NERC to submit additional information. See Order No. 693 at P 1320. (“The Commission will not approve
or remand MOD-025-1 until the ERO submits additional information.”).
24
The Commission directed NERC to modify the Reliability Standard by adding clarifying information,
specifically regarding what approval is required and when the 30-day period starts. Order No. 693 at P 1311 (“We
repeat our concern that Requirement R2, which specifies that the ‘regional reliability organization shall provide
generator gross and net real power capability verification within 30 calendar days of approval,’ is not clear. The
requirement lacks a definition of what approval is required and when the 30-day period starts. Therefore, we direct
the ERO to modify this Reliability Standard by adding information that will clarify this requirement.”).

10

determined” 25; and (3) the Commission directed NERC to require verification of Reactive Power
capability at multiple points over a unit’s operating range. 26
The first directive to clarify Requirement R2 of MOD-024-1 is satisfied by
Requirement R1, Part 1.2 of proposed Reliability Standard MOD-025-2 , which specifies that a
completed Attachment 2 (or a form containing the same information as identified in Attachment
2) must be submitted by a Generator Owner to its Transmission Planner within 90 calendar days
of either (i) the date the data is recorded for a staged test; or (ii) the date the data is selected for
verification using historical operational data.
The Commission’s second directive to “develop appropriate requirements to document
test conditions and the relationships between test conditions and generator output so that the
amount of power that can be expected to be delivered from a generator at different conditions,
such as peak summer conditions, can be determined” 27 is satisfied by Part 1.1 of Requirement R1
of proposed Reliability Standard MOD-025-2, which requires entities to verify the Real Power
capability of its generating units in accordance with Attachment 1. Section 3.4 of Attachment 1
includes the ambient conditions during a verification period such as:
•
•
•
•

Ambient air temperature
Relative humidity
Cooling water temperature
Other data as determined to be applicable by the Generator Owner to perform
corrections for ambient conditions.

Therefore, Proposed Reliability Standard MOD-025-2 provides for the determination of
the amount of power that can be expected to be delivered from a generator under different
conditions, including peak summer conditions, as directed by the Commission in Order No. 693.
25

Order No. 693 at P 1310.
Order No. 693 at P 1321. (“The Commission “direct[ed] the ERO to modify MOD-025-1 to require
verification of reactive power capability at multiple points over a unit’s operating range.”).
27
Order No. 693 at P 1310.
26

11

Attachment 1 of proposed Reliability Standard MOD-025-2 satisfies the Commission’s
third directive in Order No. 693 (at P 1321) to require verification of Reactive Power capability
at multiple points over a unit’s operating range. 28 Sections 2.1 through 2.4 of Attachment 1
require the verification of Reactive Power capability at multiple points over a unit’s operating
range. For example, Section 2.1 requires the verification of synchronous generating unit’s
maximum Real Power and lagging Reactive Power for a minimum of one hour.
Section 2.2 requires verification of the Reactive Power capability of all applicable
Facilities, other than wind and photovoltaic, for maximum overexcited (lagging) and underexcited (leading) reactive capability under several conditions. 29 Collectively, Sections 2.1
through 2.4 of Attachment 1 satisfy the Commission’s directive to require verification of reactive
power capability at multiple points over a unit’s operating range.
Provided below is a justification of proposed Reliability Standard MOD-025-2 on a
Requirement by Requirement basis.
Proposed Requirements – MOD-025-2
R1.

Each Generator Owner shall provide its Transmission Planner with verification of the
Real Power capability of its applicable Facilities as follows: [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning]
1.1. Verify the Real Power capability of its generating units in accordance with
Attachment 1.
1.2. Submit a completed Attachment 2 (or a form containing the same information as
identified in Attachment 2) to its Transmission Planner within 90 calendar days of

28

See MOD-025-2, Attachment 1, Sections 2.1 through 2.2.
Attachment 1, Section 2.2 provides:
2.2. Verify Reactive Power capability of all applicable Facilities, other than wind and photovoltaic, for
maximum overexcited (lagging) and under-excited (leading) reactive capability for the following conditions:
2.2.1 At the minimum Real Power output at which they are normally expected to operate collect
maximum leading and lagging reactive values as soon as a limit is reached.
2.2.2 At maximum Real Power output collect maximum leading reactive values as soon as a limit
is reached.
2.2.3 Nuclear Units are not required to perform Reactive Power verification at minimum Real
Power output.
29

12

either (i) the date the data is recorded for a staged test; or (ii) the date the data is
selected for verification using historical operational data.

Requirement R1 addresses Real Power and requires Generator Owners to verify the Real
Power capability of its generating units and provide that verification to its Transmission Planner.

R2.

Each Generator Owner shall provide its Transmission Planner with verification of the
Reactive Power capability of its applicable Facilities as follows: [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning]
2.1. Verify, in accordance with Attachment 1, (i) the Reactive Power capability
of its generating units and (ii) the Reactive Power capability of its synchronous
condenser units.
2.2. Submit a completed Attachment 2 (or a form containing the same information
as identified in Attachment 2) to its Transmission Planner within 90 calendar days
of either (i) the date the data is recorded for a staged test; or (ii) the date the data
is selected for verification using historical operational data.
Requirement R2 addresses Reactive Power and requires Generator Owners to verify the

Reactive Power capability of its generating units and provide that verification to its Transmission
Planner.

R3.

Each Transmission Owner shall provide its Transmission Planner with verification of the
Reactive Power capability of its applicable Facilities as follows: [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning]
3.1. Verify, in accordance with Attachment 1, the Reactive Power capability of its
synchronous condenser units.
3.2. Submit a completed Attachment 2 (or a form containing the same information
as identified in Attachment 2) to its Transmission Planner within 90 calendar days
of either (i) the date the data is recorded for a staged test; or (ii) the date the data
is selected for verification using historical operational data.

Like Requirement R2, Requirement R3 addresses Reactive Power, although Requirement
R2 applies to Transmission Owners and requires Transmission Owners to verify the Reactive

13

Power capability of applicable Facilities and provide that verification to its Transmission
Planner.
B. MOD-026-1 -- Verification of Models and Data for Generator Excitation Control
System or Plant Volt/Var Control Functions
Proposed Reliability Standard MOD-026-1 is a new Reliability Standard and consists of
six Requirements and an Attachment (Attachment 1, Excitation Control System or Plant
Volt/Var Function Model Verification Periodicity). The primary function of the excitation
system is to regulate voltage and thereby control var flow in the system. When the behavior of
generators is to be simulated accurately in power system stability studies, it is essential that the
excitation systems of the generators be modeled in sufficient detail. Proposed Reliability
Standard MOD-026-1 ensures that the generator excitation control system or plant volt/var
control function model and the model parameters used in dynamic simulations performed by the
Transmission Planner accurately represent the generator excitation control system or plant
volt/var control function behavior when assessing BES reliability. Proposed Reliability Standard
MOD-026-1 is applicable to Generator Owners and Transmission Planners.
Proposed Requirements – MOD-026-1
R1.

Each Transmission Planner shall provide the following requested information to the
Generator Owner within 90 calendar days of receiving a written request : [Violation Risk
Factor: Lower] [Time Horizon: Operations Planning]
•

Instructions on how to obtain the list of excitation control system or plant volt/var
control function models that are acceptable to the Transmission Planner for use in
dynamic simulation,

•

Instructions on how to obtain the dynamic excitation control system or plant
volt/var control function model library block diagrams and/or data sheets for
models that are acceptable to the Transmission Planner, or

•

Model data for any of the Generator Owner’s existing applicable unit specific
excitation control system or plant volt/var control function contained in the
Transmission Planner’s dynamic database from the current (in-use) models,
including generator MVA base.

14

Requirement R1 of proposed Reliability Standard MOD-026-1 is intended to ensure that
the Transmission Planner provides information to the Generator Owner necessary to ensure that
they provide a useable model in an acceptable format. This ensures that Generator Owners can
comply with Requirement R2 and in turn, provide information to Transmission Planners.

R2.

Each Generator Owner shall provide for each applicable unit, a verified generator
excitation control system or plant volt/var control function model, including
documentation and data (as specified in Part 2.1) to its Transmission Planner in
accordance with the periodicity specified in MOD-026 Attachment 1. [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
2.1.

Each applicable unit’s model shall be verified by the Generator Owner using one
or more models acceptable to the Transmission Planner. Verification for
individual units less than 20 MVA (gross nameplate rating) in a generating plant
(per Section 4.2.1.2, 4.2.2.2, or 4.2.3.2) may be performed using either individual
unit or aggregate unit model(s), or both. Each verification shall include the
following:
2.1.1. Documentation demonstrating the applicable unit’s model response
matches the recorded response for a voltage excursion from either a staged
test or a measured system disturbance,
2.1.2. Manufacturer, model number (if available), and type of the excitation
control system including, but not limited to static, AC brushless, DC
rotating, and/or the plant volt/var control function (if installed),
2.1.3. Model structure and data including, but not limited to reactance, time
constants, saturation factors, total rotational inertia, or equivalent data for
the generator,
2.1.4. Model structure and data for the excitation control system, including the
closed loop voltage regulator if a closed loop voltage regulator is installed
or the model structure and data for the plant volt/var control function
system,
2.1.5. Compensation settings (such as droop, line drop, differential
compensation), if used, and
2.1.6. Model structure and data for power system stabilizer, if so equipped.

Requirement R2 of proposed Reliability Standard MOD-026-1 ensures that Generator
Owners provide Transmission Planners a verified generator excitation control system or plant
volt/var control function model. The testing of excitation systems to validate their performance
15

specifications and to construct models can be a time consuming task 30 and Attachment 1,
Excitation Control System or Plant Volt/Var Function Model Verification Periodicity, which is
incorporated into Requirement R2, reflects these realities. Initial validation testing should be
part of equipment commissioning. Initial verification for a new applicable unit or for an existing
applicable unit with new excitation control system or plant volt/var control function equipment
installed is required by row number 3 of Attachment 1 within 365 calendar days after the
commissioning date. Testing of excitation limiters is complicated since it involves verifying that
once engaged, the limiter is capable of controlling the excitation level in a stable manner.
The purpose of Requirement R2 is to verify that the generator excitation control system
or plant volt/var control function model and the model parameters used in dynamic simulations
performed by the Transmission Planner accurately represent the generator excitation control
system or plant volt/var control function behavior when assessing BES reliability.

R3.

Each Generator Owner shall provide a written response to its Transmission Planner
within 90 calendar days of receiving one of the following items for an applicable unit:
•

Written notification from its Transmission Planner (in accordance with Requirement
R6) that the excitation control system or plant volt/var control function model is not
usable,

•

Written comments from its Transmission Planner identifying technical concerns with
the verification documentation related to the excitation control system or plant
volt/var control function model, or

•

Written comments and supporting evidence from its Transmission Planner indicating
that the simulated excitation control system or plant volt/var control function model
response did not match the recorded response to a transmission system event.

The written response shall contain either the technical basis for maintaining the current
model, the model changes, or a plan to perform model verification[FN3] (in accordance
with Requirement R2). [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]

30

See IEEE Task Force on Generator Model Validation Testing of the Power System Stability Subcommittee,
“Guidelines for Generator Stability Model Validation Testing,” at 7, IEEE PES General Meeting 2007, paper
07GM1307.

16

[FN 3: If verification is performed, the 10-year period as outlined in MOD-026
Attachment 1 is reset.]
Requirement R3 of proposed Reliability Standard MOD-026-1 provides response
requirements for a Generator Owner when it receives certain requests from the Transmission
Planner. This communication ensures that Generator Owners have an obligation to respond in a
timely fashion when there are demonstrated problems with a model that was provided by the
Generator Owner in accordance with Requirement R2.
R4.

Each Generator Owner shall provide revised model data or plans to perform model
verification[FN4] (in accordance with Requirement R2) for an applicable unit to its
Transmission Planner within 180 calendar days of making changes to the excitation
control system or plant volt/var control function that alter the equipment response
characteristic.[FN5] [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
[FN 4: Ibid]
[FN 5: Exciter, voltage regulator, plant volt/var or power system stabilizer control
replacement including software alterations that alter excitation control system equipment
response, plant digital control system addition or replacement, plant digital control
system software alterations that alter excitation control system equipment response, plant
volt/var function equipment addition or replacement (such as static var systems, capacitor
banks, individual unit excitation systems, etc), a change in the voltage control mode (such
as going from power factor control to automatic voltage control, etc), exciter, voltage
regulator, impedance compensator, or power system stabilizer settings change. Automatic
changes in settings that occur due to changes in operating mode do not apply to
Requirement R4.]

Requirement R4 of proposed Reliability Standard MOD-026-1 ensures that when a
Generator Owner makes a change to an applicable unit that would affect the model provided in
accordance with Requirement R2, the Generator Owner then has an obligation to determine
whether there is an impact on the model and to provide the Transmission Planner with revised
model data or plans to perform model verification.

17

R5.

Each Generator Owner shall provide a written response to its Transmission Planner,
within 90 calendar days following receipt of a technically justified[FN6] unit request
from the Transmission Planner to perform a model review of a unit or plant that includes
one of the following: [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
• Details of plans to verify the model (in accordance with Requirement R2), or
• Corrected model data including the source of revised model data such as discovery of
manufacturer test values to replace generic model data or updating of data parameters
based on an on-site review of the equipment.
[FN 6: Technical justification is achieved by the Transmission Planner demonstrating
that the simulated unit or plant response does not match the measured unit or plant
response.
Requirement R5 of proposed Reliability Standard MOD-026-1 ensures that there is a

process for Transmission Planners to request a model review for technically justified units not
specified in the standard Applicability section but that meet or exceed the Registry Criteria unit
MVA thresholds. Footnote 2 clarifies that technical justification is achieved by the Transmission
Planner demonstrating that the simulated unit or plant response does not match the measured unit
or plant response. Requirement R5 allows Generator Owners 90 days to provide Transmission
Planners with: (1) its plans to verify the model or (2) corrected model data.

R6.

Each Transmission Planner shall provide a written response to the Generator Owner
within 90 calendar days of receiving the verified excitation control system or plant
volt/var control function model information in accordance with Requirement R2 that the
model is usable (meets the criteria specified in Parts 6.1 through 6.3) or is not usable.
6.1.
The excitation control system or plant volt/var control function model initializes
to compute modeling data without error,
6.2.
A no-disturbance simulation results in negligible transients, and
6.3.
For an otherwise stable simulation, a disturbance simulation results in the
excitation control and plant volt/var control function model exhibiting positive
damping.
If the model is not usable, the Transmission Planner shall provide a technical description
of why the model is not usable. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]

18

Requirement R6 of proposed Reliability Standard MOD-026-1 requires the Transmission
Planner to inform the Generator Owner within 90 calendar days whether a model is useable or
not. The response from the Transmission Planner verifies that the Transmission Planner has
sufficient information and ensures that the verification process is complete.
C. MOD-027-1 – Verification of Models and Data for Turbine/Governor and Load
Control or Active Power/Frequency Control Functions
Proposed Reliability Standard MOD-027-1 is a new Reliability Standard and consists of
five Requirements. The purpose of proposed Reliability Standard MOD-027-1 is to verify that
the turbine/governor and load control or active power/frequency control model and the model
parameters, used in dynamic simulations that assess BES reliability, accurately represent
generator unit Real Power response to system frequency variations.
Proposed Requirements MOD-027-1
R1.

Each Transmission Planner shall provide the following requested information to the
Generator Owner within 90 calendar days of receiving a written request: [Violation
Risk Factor: Lower] [Time Horizon: Operations Planning]
• Instructions on how to obtain the list of turbine/governor and load control or active
power/frequency control system models that are acceptable to the Transmission
Planner for use in dynamic simulation,
• Instructions on how to obtain the dynamic turbine/governor and load control or active
power/frequency control function model library block diagrams and/or data sheets for
models that are acceptable to the Transmission Planner, or
• Model data for any of the Generator Owner’s existing applicable unit specific
turbine/governor and load control or active power/frequency control system contained
in the Transmission Planner’s dynamic database from the current (in-use) models.
Requirement R1 of proposed Reliability Standard MOD-027-1 requires Transmission

Planners to provide information to Generator Owners upon written request within 90 calendar
days. This information ensures that Generator Owners can provide Transmission Planners the
information required in Requirements R2 and R4 of proposed Reliability Standard MOD-027-1.

19

R2.

Each Generator Owner shall provide, for each applicable unit, a verified turbine/governor
and load control or active power/frequency control model, including documentation and
data (as specified in Part 2.1) to its Transmission Planner in accordance with the
periodicity specified in MOD-027 Attachment 1. [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
2.1. Each applicable unit’s model shall be verified by the Generator Owner using one or
more models acceptable to the Transmission Planner. Verification for individual units
rated less than 20 MVA (gross nameplate rating) in a generating plant (per Section
4.2.1.2, 4.2.2.2, or 4.2.3.2) may be performed using either individual unit or aggregate
unit model(s) or both. Each verification shall include the following:
2.1.1. Documentation comparing the applicable unit’s MW model response to
the recorded MW response for either:
• A frequency excursion from a system disturbance that meets MOD027 Attachment 1 Note 1 with the applicable unit on-line,
• A speed governor reference change with the applicable unit online, or
• A partial load rejection test,[FN 2]
2.1.2. Type of governor and load control or active power control/frequency
control1 equipment,
[FN2: Differences between the control mode tested and the final simulation model must
be identified, particularly when analyzing load rejection data. Most controls change gains
or have a set point runback which takes effect when the breaker opens. Load or set point
controls will also not be in effect once the breaker opens. Some method of accounting for
these differences must be presented if the final model is not validated from on-line data
under the normal operating conditions under which the model is expected to apply.]
Requirement R2 of proposed Reliability Standard MOD-027-1 requires Generator

Owners to provide Transmission Planners information and documentation as specified in
Attachment 1. Attachment 1, Turbine/Governor and Load Control or Active Power/Frequency
Control Model Periodicity, is a table that lists verification conditions and the accompanying
required actions. In addition to obtaining model data, the tests performed to gather this
information may uncover latent defects that could lead to inappropriate unit response during
system disturbances and thereby improve reliability. 31

R3.

Each Generator Owner shall provide a written response to its Transmission Planner
within 90 calendar days of receiving one of the following items for an applicable unit.

31

See IEEE Task Force on Generator Model Validation Testing of the Power System Stability Subcommittee,
“Guidelines for Generator Stability Model Validation Testing,” at 1, IEEE PES General Meeting 2007, paper
07GM1307.

20

•

Written notification, from its Transmission Planner (in accordance with Requirement
R5) that the turbine/governor and load control or active power/frequency control
model is not “usable,”
• Written comments from its Transmission Planner identifying technical concerns with
the verification documentation related to the turbine/governor and load control or
active power/frequency control model, or
• Written comments and supporting evidence from its Transmission Planner indicating
that the simulated turbine/governor and load control or active power/frequency
control response did not approximate the recorded response for three or more
transmission system events.
The written response shall contain either the technical basis for maintaining the current
model, the model changes, or a plan to perform model verification[FN 3] (in accordance
with Requirement R2). [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
[FN3: If verification is performed, the 10 year period as outlined in MOD-027
Attachment 1 is reset.]
Requirement R3 of proposed Reliability Standard MOD-027-1 ensures that there is
appropriate communication between Generator Owners and Transmission Planners when an
issue is identified with a model or where there is a difference between the model and actual
recorded events for three or more transmission system events. The evidence of compliance with
Requirement R3, included in Measure M3, 32 would consist of the Generator Owner’s dated
written response containing the information identified in Requirement R3 and dated evidence of
the transmittal of the response.

R4.

Each Generator Owner shall provide revised model data or plans to perform model
Verification[FN 4] (in accordance with Requirement R2) for an applicable unit to its
Transmission Planner within 180 calendar days of making changes to the
turbine/governor and load control or active power/frequency control system that alter the
equipment response characteristic[FN 5]. [Violation Risk Factor: Lower] [Time Horizon:
Operations Planning]
[FN4: Ibid.
[FN5: Control replacement or alteration including software alterations or plant digital
control system addition or replacement, plant digital control system software alterations

32

Measures identify the evidence or types of evidence needed to demonstrate compliance with the associated
Requirement. See NERC Standard Processes Manual, available here:
http://www.nerc.com/pa/Stand/Resources/Documents/Appendix3AStandardsProcessesManual.pdf.

21

that alter droop, and/or dead band, and/or frequency response and/or a change in the
frequency control mode (such as going from droop control to constant MW control, etc).]
Requirement R4 of proposed Reliability Standard MOD-027-1 ensures that Generator
Owners provide Transmission Planners with updated information when changes occur; this
ensures that the information in Requirement R2 is updated when necessary (i.e., when changes
are made to the turbine/governor and load control or active power/frequency control system that
alter the equipment response characteristic). The evidence of compliance for Requirement R4,
included in Measure M4, would consist of dated revised model data or dated plans to perform a
model verification and dated evidence of transmittal.

R5.

Each Transmission Planner shall provide a written response to the Generator Owner
within 90 calendar days of receiving the turbine/governor and load control or active
power/frequency control system verified model information in accordance with
Requirement R2 that the model is usable (meets the criteria specified in Parts 5.1 through
5.3) or is not usable.
5.1. The turbine/governor and load control or active power/frequency control
function model initializes to compute modeling data without error,
5.2. A no-disturbance simulation results in negligible transients, and
5.3. For an otherwise stable simulation, a disturbance simulation results in the
turbine/governor and load control or active power/frequency control model
exhibiting positive damping.
If the model is not usable, the Transmission Planner shall provide a technical description
of why the model is not usable. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
Requirement R5 of proposed Reliability Standard MOD-027-1 requires Transmission

Planners to provide verification to Generator Owners that the model provided (pursuant to
Requirement R2 or R4) is useable. This is necessary to ensure that there is appropriate
communication between Generator Owners and Transmission Planners and ensures that if the
model provided by the Generator Owner is not useable, the Generator Owner has an appropriate
technical explanation of the issue. Generator Owners are also then obligated to provide a written
response, pursuant to Requirement R3, within 90 calendar days.
22

D. PRC-019-1 – Coordination of Generating Unit or Plant Capabilities, Voltage
Regulating Controls, and Protection

Proposed Reliability Standard PRC-019-1 is a new Reliability Standard and consists of
two Requirements. The purpose of the proposed Reliability Standard is to verify coordination of
generating unit Facility or synchronous condenser voltage regulating controls, limit functions,
equipment capabilities and Protection System settings. Proposed Reliability Standard PRC-0191 is applicable to Generator Owners and Transmission Owners that own synchronous
condenser(s).
Proposed Requirements – PRC-019-1
R1.

At a maximum of every five calendar years, each Generator Owner and Transmission
Owner with applicable Facilities shall coordinate the voltage regulating system controls,
(including in-service[FN 1] limiters and protection functions) with the applicable
equipment capabilities and settings of the applicable Protection System devices and
functions. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
1.1. Assuming the normal automatic voltage regulator control loop and steady-state
system operating conditions, verify the following coordination items for each
applicable Facility:
1.1.1. The in-service limiters are set to operate before the Protection System of
the applicable Facility in order to avoid disconnecting the generator
unnecessarily.
1.1.2. The applicable in-service Protection System devices are set to operate to
isolate or de-energize equipment in order to limit the extent of damage
when operating conditions exceed equipment capabilities or stability
limits.
[FN 1: Limiters or protection functions that are installed and activated on the generator or
synchronous condenser.]
Requirement R1 of proposed Reliability Standard PRC-019-1 requires Generator Owners and

Transmission Owners to coordinate voltage regulating system controls with the equipment of the
applicable Protection System devices and functions. Measure M1 states that each Generator
Owner and Transmission Owner should have evidence that it coordinated the voltage regulating
system controls and examples of coordination are provided in the Reference section of the
23

standard. The Reference Section of proposed Reliability Standard PRC-019-1 states that
evidence of coordination associated with Requirement R1 may be in the form of:
•
•
•
•

P-Q Diagram (Example in Attachment 1), or
R-X Diagram (Example in Attachment 2), or
Inverse Time Diagram (Example in Attachment 3) or,
Equivalent tables or other evidence

This evidence should include the equipment capabilities and the operating region for the
limiters and protection functions. Equipment limits, types of limiters and protection functions
which could be coordinated include (but are not limited to):
•
•
•
•
•
•
•
•

Field over-excitation limiter and associated protection functions.
Inverter over current limit and associated protection functions.
Field under-excitation limiter and associated protection functions.
Generator or synchronous condenser reactive capabilities.
Volts per hertz limiter and associated protection functions.
Stator over-voltage protection system settings.
Generator and transformer volts per hertz capability.
Time vs. field current or time vs. stator current.

(NOTE: This listing is for reference only. This standard does not require the installation or
activation of any of the above limiter or protection functions.)
R2. Within 90 calendar days following the identification or implementation of systems,
equipment or setting changes that will affect the coordination described in Requirement
R1, each Generator Owner and Transmission Owner with applicable Facilities shall
perform the coordination as described in Requirement R1. These possible systems,
equipment or settings changes include, but are not limited to the following [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]:
• Voltage regulating settings or equipment changes;
• Protection System settings or component changes;
• Generating or synchronous condenser equipment capability changes; or
• Generator or synchronous condenser step-up transformer changes.
Requirement R2 of proposed Reliability Standard PRC-019-1applies when there are
equipment or setting changes. Collectively, Requirements R1 and R2 ensure an appropriate level
of coordination between Generator Owners and Transmission Owners. The evidence of

24

compliance with Requirement R2 (included in Measure M2) would consist of dated
documentation that demonstrates that the specified intervals in Requirement R2 have been met.

E. PRC-024-1 – Generator Frequency and Voltage Protective Relay Settings
Proposed Reliability Standard PRC-024-1 is a new Reliability Standard and consists of
four Requirements and two Attachments. The purpose of proposed Reliability Standard PRC024-1 is to ensure that Generator Owners set their generator protective relays such that
generating units remain connected during defined frequency and voltage excursions.
Attachment 1 is the Off Nominal Frequency Capability Curve and establishes a “no trip
zone;” it is incorporated into the language of Requirement R1 of proposed Reliability Standard
PRC-024-1. The X-axis of the Attachment 1 curve represents time and the scale is logarithmic.
The Y-axis of the Attachment 1 curve represents the frequency of the specific Interconnection.
The “no trip zone” does not include the colored lines delineating the zones illustrated in
Attachment 1. The curve data points provided in the tables of Attachment 1 detail the exact
points on the curve for each Interconnection and represent the amount of time a generator needs
to stay connected at specific defined frequency excursions. For the Eastern Interconnection, the
relays for each generator are expected to be set to remain online between frequencies of greater
than (and not including) 60.5 hz and less than (and not including) 59.5 hz. For all other
Interconnections, the relays for each generator are expected to be set to remain online between
frequencies of greater than (and not including) 60.6 hz and less than (and not including) 59.4 hz.
For example, in the Western Interconnection if the frequency drops to 58.0 hz the relays are
required to be set such that they do not trip the generating units for up to (and not including) 12
seconds. For time periods of 12 seconds and beyond, the proposed Standard allows for the relays
to be set to trip the generating units.
25

Attachment 2 is the Voltage Ride-Through Time Duration Curve and is incorporated into
the language of Requirement R2 of proposed Reliability Standard PRC-024-1.
1. Commission Directives
Proposed Reliability Standard PRC-024-1 satisfies two Commission directives from
Paragraph 1787 of Order No. 693.
1787. In the NOPR, the Commission identified an implicit assumption in the
TPL Reliability Standards that all generators are required to ride through the
same types of voltage disturbances and remain in service after the fault is
cleared. This implicit assumption should be made explicit. Commenters
agree with the proposed requirement for all generators to ride through the
same set of Category B and C events as required for wind generators. The
Commission understands that [United States Nuclear Regulatory
Commission (“NRC”)] has both degraded voltage and loss of voltage
requirements. The degraded voltage requirement allows the voltage at the
auxiliary power system busses to go below the minimum value for a time
frame that is usually much longer than normal fault clearing time. If a
specific nuclear power plant has an NRC requirement that would force it to
trip off-line if its auxiliary power system voltage was depressed below some
minimum voltage, the simulation should include the tripping of the plant in
addition to the faulted facilities. In this regard, the Commission agrees that
NRC requirements should be used when implementing the Reliability
Standards. Using NRC requirements as input will assure that there is
consistency between the Reliability Standards and the NRC requirement that
the system is accurately modeled. Accordingly, the Commission directs the
ERO to modify the Reliability Standard to explicitly require either that all
generators are capable of riding through the same set of Category B and C
contingencies, as required by wind generators in Order No. 661, or that
those generators that cannot ride through be simulated as tripping. If a
generator trips due to low voltage from a single contingency, the initial trip
of the faulted element and the resulting trip of the generator would be
governed by Category B contingencies and performance criteria. 33

Requirement R2 and Attachment 2 (which is incorporated), of proposed Reliability
Standard PRC-024-1 satisfy the Commission’s directive in Order No. 693 to “explicitly require
either that all generators are capable of riding through the same set of Category B and C

33

Order No. 693 at P 1787(internal citation omitted)(emphasis added).

26

contingencies, as required by wind generators in Order No. 661, or that those generators that
cannot ride through be simulated as tripping.” 34
The technical basis for the curves in Attachment 2 of NERC Standard PRC-024-1 comes
principally from The Technical Basis for the New WECC Voltage Ride-Though (VRT) Standard,
a whitepaper developed by the WECC Wind Generation Task Force (“WGTF”). 35
During the process of drafting the proposed Reliability Standard PRC-024-1, a
comparison was done by a utility company between the results of fault recordings and studies
from their region with the curves in Attachment 2 and this demonstrated that the curves properly
bounded the voltage profiles actually experienced. It should be noted that, unlike a number of
other regulatory requirements for voltage ride-through, the proposed WECC curves (and
subsequently the curves in PRC-024-1 Attachment 2) contain requirements for the high voltage
excursions that occur following clearing of a fault on the transmission system. The standard
drafting team reviewed these curves to ensure they did not compromise equipment safety due to
overexcitation of magnetic circuits as described in IEEE 36 and ANSI 37 standards. The standard
drafting team also had the benefit of input from a manufacturer of power conversion electronic
equipment to ensure the curves were realistic from their perspective.
Requirement R3 allows NRC requirements to supersede portions of the voltage and
frequency ride through criteria in proposed Reliability Standard PRC-024-1. Requirement R3
allows generators an exemption from portions of the ride through curves for documented
regulatory limitations. The standard drafting team asserts that NRC requirements qualify as
34

Order No. 693 at P 1787.
Available here: http://www.wecc.biz/Standards/Development/WECC-60/Shared Documents/The
Technical Basis for the New WECC Voltage Ride-Through (VRT).doc. In developing the whitepaper, the WGTF
examined the voltage profiles of various line faults in the Western Electricity Coordinating Council (“WECC”)
region and drew a voltage vs. time envelope around that encompassed all of the normally cleared faults. The
WGTF also reviewed various international voltage ride-through standards and found the proposed WECC curves.
36
Institute of Electrical and Electronics Engineers (“IEEE”).
37
American National Standards Institute (“ANSI”).
35

27

regulatory limitations for the purposes of proposed Reliability Standard PRC-024-1 and
therefore, Requirement R3 satisfies the Commission’s guidance that “NRC requirements should
be used when implementing the Reliability Standards.” 38
Proposed Requirements – PRC-024-1
R1.

Each Generator Owner that has generator frequency protective relaying[FN1] activated to
trip its applicable generating unit(s) shall set its protective relaying such that the
generator frequency protective relaying does not trip the applicable generating unit(s)
within the “no trip zone” of PRC-024 Attachment 1, subject to the following exceptions:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
• Generating unit(s) may trip if the protective functions (such as out-of-step functions
or loss-of-field functions) operate due to an impending or actual loss of synchronism
or, for asynchronous generating units, due to instability in power conversion control
equipment.
•

Generating unit(s) may trip if clearing a system fault necessitates disconnecting (a)
generating unit(s).

•

Generating unit(s) may trip within a portion of the “no trip zone” of PRC-024
Attachment 1 for documented and communicated regulatory or equipment limitations
in accordance with Requirement R3.
[FN1: Each Generator Owner is not required to have frequency or voltage protective
relaying (including but not limited to frequency and voltage protective functions for
discrete relays, volts per hertz relays evaluated at nominal frequency, multi-function
protective devices or protective functions within control systems that directly trip or
provide tripping signals to the generator based on frequency or voltage inputs)
installed or activated on its unit.]

Requirement R1 of proposed Reliability Standard PRC-024-1 ensures that generating
units remain connected during frequency excursions.

R2.

Each Generator Owner that has generator voltage protective relaying[FN 1] activated to
trip its applicable generating unit(s) shall set its protective relaying such that the
generator voltage protective relaying does not trip the applicable generating unit(s) as a
result of a voltage excursion (at the point of interconnection[FN 2]) caused by an event
on the transmission system external to the generating plant that remains within the “no
trip zone” of PRC-024 Attachment 2. If the Transmission Planner allows less stringent
voltage relay settings than those required to meet PRC-024 Attachment 2, then the
Generator Owner shall set its protective relaying within the voltage recovery
characteristics of a location-specific Transmission Planner’s study. Requirement R2 is

38

Id.

28

subject to the following exceptions: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
•

Generating unit(s) may trip in accordance with a Special Protection System (SPS) or
Remedial Action Scheme (RAS).

•

Generating unit(s) may trip if clearing a system fault necessitates disconnecting (a)
generating unit(s).

•

Generating unit(s) may trip by action of protective functions (such as out-of-step
functions or loss-of-field functions) that operate due to an impending or actual loss of
synchronism or, for asynchronous generating units, due to instability in power
conversion control equipment.

•

Generating unit(s) may trip within a portion of the “no trip zone” of PRC-024 Attachment
2 for documented and communicated regulatory or equipment limitations in accordance
with Requirement R3.

[FN1 Each Generator Owner is not required to have frequency or voltage protective
relaying (including but not limited to frequency and voltage protective functions for
discrete relays, volts per hertz relays evaluated at nominal frequency, multi-function
protective devices or protective functions within control systems that directly trip or
provide tripping signals to the generator based on frequency or voltage inputs) installed
or activated on its unit.
[FN2 For the purposes of this standard, point of interconnection means the transmission
(high voltage) side of the generator step-up or collector transformer.]

Requirement R2 and Attachment 2 (which is incorporated), of proposed Reliability
Standard PRC-024-1 satisfy the Commission’s directive in Order No. 693 to “explicitly require
either that all generators are capable of riding through the same set of Category B and C
contingencies, as required by wind generators in Order No. 661, or that those generators that
cannot ride through be simulated as tripping.” 39 Requirement R2 ensures that generating unit
protection systems do not disconnect the generator from the grid during the voltage excursions
defined in Attachment 2. The standard drafting team believes the voltage profile described in
Attachment 2 covers excursions that would be expected under Category B and C contingencies.

39

Order No. 693 at P 1787.

29

R3.

Each Generator Owner shall document each known regulatory or equipment
limitation[FN3] that prevents an applicable generating unit with generator frequency or
voltage protective relays from meeting the relay setting criteria in Requirements R1 or R2
including (but not limited to) study results, experience from an actual event, or
manufacturer’s advice. [Violation Risk Factor: Lower] [Time Horizon: Long-term
Planning]
3.1.
The Generator Owner shall communicate the documented regulatory or
equipment limitation, or the removal of a previously documented regulatory or
equipment limitation, to its Planning Coordinator and Transmission Planner
within 30 calendar days of any of the following:
• Identification of a regulatory or equipment limitation.
• Repair of the equipment causing the limitation that removes the limitation.
• Replacement of the equipment causing the limitation with equipment that
removes the limitation.
• Creation or adjustment of an equipment limitation caused by consumption of
the cumulative turbine life-time frequency excursion allowance.
[FN 3: Excludes limitations that are caused by the setting capability of the generator
frequency and voltage protective relays themselves but does not exclude
limitations originating in the equipment that they protect.]

Requirement R3 of proposed Reliability Standard PRC-024-1 requires Generator Owners
to document known regulatory or equipment limitations and to communicate these limitations to
Planning Coordinators and Transmissions within 30 days of identifying a limitation or repair or
replacement of the equipment causing the limitation. This allows the Transmission Planners to
properly simulate the performance of the protection systems of those generators that must have
their protection systems set to operate within the No Trip Zones described in Requirements R1
and R2.

R4.

Each Generator Owner shall provide its applicable generator protection trip settings
associated with Requirements R1 and R2 to the Planning Coordinator or Transmission
Planner that models the associated unit within 60 calendar days of receipt of a written
request for the data and within 60 calendar days of any change to those previously
requested trip settings unless directed by the requesting Planning Coordinator or
Transmission Planner that the reporting of relay setting changes is not required.
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

30

Requirement R4 of proposed Reliability Standard PRC-024-1 requires Generator Owners
to provide its protection trip settings associated with Requirements R1 and R2 to the Planning
Coordinator or Transmission Planner within 60 days of (1) a written request for that information
or (2) a change to any previously requested trip settings.
F. Enforceability of the Proposed Reliability Standards
The proposed Reliability Standards include Violation Risk Factors (“VRFs”) and
Violation Severity Levels (“VSLs”). The VSLs provide guidance on the way that NERC will
enforce the Requirements of the proposed Reliability Standard. The VRFs and VSLs for the
proposed Reliability Standards comport with NERC and Commission guidelines related to their
assignment. For a detailed review of the VRFs, the VSLs, and the analysis of how the VRFs and
VSLs were determined using these guidelines, please see Exhibit E.
The proposed Reliability Standards also include Measures that support each Requirement
by clearly identifying what is required and how the Requirement will be enforced. These
Measures help ensure that the Requirements will be enforced in a clear, consistent, and nonpreferential manner and without prejudice to any party. 40

40

Order No. 672 at P 327 (“There should be a clear criterion or measure of whether an entity is in compliance
with a proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance
so that it can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.”).

31

V.

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

approve the proposed Reliability Standards and associated elements included in
Exhibit A, effective as proposed herein;

•

approve the implementation plan included in Exhibit B; and

•

approve the retirement of Reliability Standards, effective as proposed herein.

Respectfully submitted,
/s/ Stacey Tyrewala
Charles A. Berardesco
Senior Vice President and General Counsel Holly
A. Hawkins
Assistant General Counsel
Stacey Tyrewala
Senior 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

May 30, 2013