NERC Petiton 725E

NERC Petition - 725E.pdf

FERC-725E, (RD16-10-000, RD17-5-000, IC17-6-000) Mandatory Reliability Standards for the Western Electric Coordinating Council

NERC Petiton 725E

OMB: 1902-0246

⚠️ Notice: This form may be outdated. More recent filings and information on OMB 1902-0246 can be found here:

Document [pdf]

Download: pdf | pdf

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 ERRATA TO VOLTAGE AND REACTIVE CONTROL
RELIABILITY STANDARDS
Shamai Elstein
Senior Counsel
Lauren A. Perotti
Counsel
Marisa Hecht
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

August 18, 2017

TABLE OF CONTENTS
BACKGROUND .................................................................................................................... 2
A.

Periodic Review of VAR-001-4.1 and VAR-002-4 ......................................................... 2

Regional Reliability Standard VAR-501-WECC-3 ......................................................... 3
NOTICES AND COMMUNICATIONS ................................................................................ 3
ERRATA.............................................................................................................................. 4

Proposed Reliability Standard VAR-001-4.2 ................................................................... 4

Proposed Reliability Standard VAR-002-4.1 ................................................................... 4

Proposed Regional Reliability Standard VAR-501-WECC-3.1 ...................................... 4
CONCLUSION .................................................................................................................... 5

Exhibit A

Exhibit B

Exhibit C

Proposed Reliability Standard VAR-001-4.2 (Voltage and Reactive Control)
Exhibit A-1

Proposed Reliability Standard VAR-001-4.2 Clean

Exhibit A-2

Proposed Reliability Standard VAR-001-4.2 Redline

Proposed Reliability Standard VAR-002-4.1 (Generator Operation for
Maintaining Network Schedules)
Exhibit B-1

Proposed Reliability Standard VAR-002-4.1 Clean

Exhibit B-2

Proposed Reliability Standard VAR-002-4.1 Redline

Proposed WECC Regional Reliability Standard VAR-501-WECC-3.1 (Power
System Stabilizer)
Exhibit C-1
3.1 Clean

Proposed WECC Regional Reliability Standard VAR-501-WECC-

Exhibit C-2
3.1 Redline

Proposed WECC Regional Reliability Standard VAR-501-WECC-

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 ERRATA TO VOLTAGE AND REACTIVE CONTROL
RELIABILITY STANDARDS
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
errata to the following two mandatory and enforceable Voltage and Reactive Control (“VAR”)
Reliability Standards, which were reaffirmed by the NERC Board of Trustees at its August 10,
2017 meeting: 4
•

VAR-001-4.1 (Voltage and Reactive Control); and

•

VAR-002-4 (Generator Operation for Maintaining Network Schedules).

In addition, NERC requests Commission approval of an errata to the following
mandatory and enforceable regional Reliability Standard for the Western Electricity
Coordinating Council (“WECC”) region:
•

VAR-501-WECC-3 (Power System Stabilizer).

16 U.S.C. § 824o (2012).
18 C.F.R. § 39.5 (2017).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006).
4
This filing serves as notice to the Commission of the reaffirmation of the standards.
2

Clean and redline versions of proposed Reliability Standards VAR-001-4.2, VAR-0024.1, and VAR-501-WECC-3.1 are attached to this petition as Exhibits A, B, and C, respectively.
BACKGROUND
A.

Periodic Review of VAR-001-4.1 and VAR-002-4

NERC conducts periodic reviews of Reliability Standards in accordance with Section 317
of the NERC Rules of Procedure and Section 13 of the NERC Standard Processes Manual. 5 In
accordance with these authorities and the NERC Reliability Standards Development Plan: 20172019, 6 NERC recently completed Project 2016-EPR-02 Enhanced Periodic Review of Voltage
and Reactive Reliability Standards. 7 This project conducted a periodic review of mandatory and
enforceable Reliability Standards VAR-001-4.1 (Voltage and Reactive Control) 8 and VAR-0024 (Generator Operation for Maintaining Network Schedules). 9
The periodic review team found that the two VAR Reliability Standards are sufficient to
protect reliability, each meets its reliability objective, and that no immediate substantive
revisions are necessary. However, the team found that there may be future opportunity to
improve non-substantive or insignificant quality and content issues. Based on the results of its
review, the periodic review team recommended reaffirming the Reliability Standards. The NERC

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.
6
NERC filed the Reliability Standards Development Plan: 2017-2019 on December 16, 2016 in Docket Nos.
RM05-17-000, RM05-25-000, and RM06-16-000.
7
More information about this project is available on the Project 2016-EPR-02 project page,
http://www.nerc.com/pa/Stand/Pages/Project-2016-EPR-02-Enhanced-Periodic-Review-of-Voltage-and-ReactiveStandards.aspx.
8
The Commission approved Reliability Standard VAR-001-4 (Voltage and Reactive Control) on August 1,
2014.See North American Electric Reliability Corp., Docket No. RD14-11-000 (Aug. 1, 2014) (delegated letter
order). The Commission approved errata version VAR-001-4.1 on November 13, 2015. See North American Electric
Reliability Corp., Docket No. RD15-6-000 (Nov. 13, 2015) (delegated letter order).
9
The Commission approved Reliability Standard VAR-002-4, which clarified the applicability of the VAR002 standard to dispersed generation resources, on May 29, 2015. See North American Electric Reliability Corp, 151
FERC ¶ 61,186 (May 29, 2015).

Standards Committee accepted this recommendation at its June 14, 2017 meeting, and on August
10, 2017, the NERC Board of Trustees voted to adopt the reaffirmed VAR Reliability Standards.
In the course of its work, the periodic review team identified and recommended changes
to correct errata in VAR-001-4.1 and VAR-002-4. In accordance with Section 12 of the NERC
Standard Processes Manual, the NERC Standards Committee approved the proposed errata
changes on June 14, 2017. The proposed errata changes are described in Section III below.
B.

Regional Reliability Standard VAR-501-WECC-3

The Commission approved WECC regional Reliability Standard VAR-501-WECC-3
(Power System Stabilizer) on April 28, 2017. 10 Following approval of the standard, nonsubstantive errors were identified in the Violation Severity Levels and Guidelines and Technical
Basis sections. In accordance with the WECC Reliability Standards Development Procedures
and Section 12 of the NERC Standard Processes Manual, the NERC Standards Committee
approved the proposed errata on July 19, 2017.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the
following: 11
Shamai Elstein*
Howard Gugel*
Senior Counsel
Director of Standards
Lauren A. Perotti*
North American Electric Reliability
Counsel
Corporation
Marisa Hecht*
3353 Peachtree Road, N.E.
Counsel
Suite 600, North Tower
North American Electric Reliability
Atlanta, GA 30326
Corporation
(404) 446-2560
1325 G Street, N.W., Suite 600
[email protected]
Washington, D.C. 20005
(202) 400-3000
[email protected]
10

North American Electric Reliability Corp., Docket No. RD17-5-000 (Apr. 28, 2017) (delegated letter

order).
11

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 (2017), to allow the inclusion
of more than two persons on the service list in this proceeding.

[email protected]
[email protected]
ERRATA
This section describes the proposed errata changes reflected in Reliability Standards
VAR-001-4.2, VAR-002-4.1, and VAR-501-WECC-3.1. Pursuant to Section 12 of the NERC
Standard Processes Manual, none of the proposed errata change the scope or intent of the
associated Reliability Standard, nor do any of the changes have any material impact on the end
users of the associated Reliability Standard.
A.

Proposed Reliability Standard VAR-001-4.2

The errata reflected in the proposed standard include: (i) corrections to the name of the
time horizon from “Operational Planning” to “Operations Planning” throughout; (ii) clarification
in Measure M1 that the time for required action is within “30 calendar days,” in accordance with
the corresponding Requirement; (iii) clarification, in Measure M3, that the entity’s evidence may
include, but is not limited to, the specified items; (iv) correction of grammar in Requirement R4
and the corresponding Measure M4; and (v) corrected capitalization of non-defined terms in
Measure M5, WECC Regional Variance Requirement E.A.18, and in the Guidelines and
Technical Basis section.
B.

Proposed Reliability Standard VAR-002-4.1

The erratum reflected in the proposed standard corrects the capitalization of the defined
term “Reactive Power” in Requirement R2, footnote 4.
C.

Proposed Regional Reliability Standard VAR-501-WECC-3.1

The errata reflected in the proposed standard consists of corrections to the Violation
Severity Levels and Guidelines and Technical Basis for Requirement R1. The reference to the

entity that receives documentation is corrected from “Transmission Planner” to “Transmission
Operator” to correspond to the language of the Requirement.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve
the proposed errata to the Reliability Standards included in Exhibits A, B, and C.

Respectfully submitted,
/s/ Lauren A. Perotti
Shamai Elstein
Senior Counsel
Lauren A. Perotti
Counsel
Marisa Hecht
Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
August 18, 2017

Exhibit A
Proposed Reliability Standard VAR-001-4.2 (Voltage and Reactive Control)

Exhibit A-1
Proposed Reliability Standard VAR-001-4.2 Clean

VAR-001-4.2 — Voltage and Reactive Control

A. Introduction
1.

Title:

Number: VAR-001-4.2

Purpose: To ensure that voltage levels, reactive flows, and reactive resources are monitored,
controlled, and maintained within limits in Real-time to protect equipment and the reliable
operation of the Interconnection.

Applicability:

Voltage and Reactive Control

4.1. Transmission Operators
4.2. Generator Operators within the Western Interconnection (for the WECC Variance)
5.

Effective Date:
5.1. The standard shall become effective on the first day of the first calendar quarter after the
date that the standard is approved by an applicable governmental authority or as otherwise
provided for in a jurisdiction where approval by an applicable governmental authority is
required for a standard to go into effect. Where approval by an applicable governmental
authority is not required, the standard shall become effective on the first day of the first
calendar quarter after the date the standard is adopted by the NERC Board of Trustees or as
otherwise provided for in that jurisdiction.

Page 1 of 15

VAR-001-4.2 — Voltage and Reactive Control

B. Requirements and Measures
R1. Each Transmission Operator shall specify a system voltage schedule (which is either a range or a
target value with an associated tolerance band) as part of its plan to operate within System
Operating Limits and Interconnection Reliability Operating Limits. [Violation Risk Factor: High]
[Time Horizon: Operations Planning]
1.1. Each Transmission Operator shall provide a copy of the voltage schedules (which is either a
range or a target value with an associated tolerance band) to its Reliability Coordinator and
adjacent Transmission Operators within 30 calendar days of a request.
M1. The Transmission Operator shall have evidence that it specified system voltage schedules using
either a range or a target value with an associated tolerance band.
For part 1.1, the Transmission Operator shall have evidence that the voltage schedules (which is
either a range or a target value with an associated tolerance band) were provided to its Reliability
Coordinator and adjacent Transmission Operators within 30 calendar days of a request. Evidence
may include, but is not limited to, emails, website postings, and meeting minutes.
R2. Each Transmission Operator shall schedule sufficient reactive resources to regulate voltage levels
under normal and Contingency conditions. Transmission Operators can provide sufficient reactive
resources through various means including, but not limited to, reactive generation scheduling,
transmission line and reactive resource switching, and using controllable load. [Violation Risk
Factor: High] [Time Horizon: Real-time Operations, Same-day Operations, and Operations Planning]
M2. Each Transmission Operator shall have evidence of scheduling sufficient reactive resources based
on their assessments of the system. For the operations planning time horizon, Transmission
Operators shall have evidence of assessments used as the basis for how resources were scheduled.
R3. Each Transmission Operator shall operate or direct the Real-time operation of devices to regulate
transmission voltage and reactive flow as necessary. [Violation Risk Factor: High] [Time Horizon:
Real-time Operations, Same-day Operations, and Operations Planning]
M3. Each Transmission Operator shall have evidence that actions were taken to operate capacitive and
inductive resources as necessary in Real-time. This may include, but is not limited to, instructions to
Generator Operators to: 1) provide additional voltage support; 2) bring resources on-line; or 3)
make manual adjustments.
R4. Each Transmission Operator shall specify the criteria that will exempt generators: 1) from following
a voltage or Reactive Power schedule, 2) from having its automatic voltage regulator (AVR) in
service or from being in voltage control mode, or 3) from having to make any associated
notifications. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
4.1 If a Transmission Operator determines that a generator has satisfied the exemption criteria, it
shall notify the associated Generator Operator.
M4. Each Transmission Operator shall have evidence of the documented criteria for generator
exemptions.
For part 4.1, the Transmission Operator shall also have evidence to show that, for each generator in
its area that is exempt: 1) from following a voltage or Reactive Power schedule, 2) from having its
Page 2 of 15

VAR-001-4.2 — Voltage and Reactive Control
automatic voltage regulator (AVR) in service or from being in voltage control mode, or 3) from
having to make any notifications, the associated Generator Operator was notified of this
exemption.
R5. Each Transmission Operator shall specify a voltage or Reactive Power schedule (which is either a
range or a target value with an associated tolerance band) at either the high voltage side or low
voltage side of the generator step-up transformer at the Transmission Operator’s discretion.
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
5.1. The Transmission Operator shall provide the voltage or Reactive Power schedule (which is
either a range or a target value with an associated tolerance band) to the associated
Generator Operator and direct the Generator Operator to comply with the schedule in
automatic voltage control mode (the AVR is in service and controlling voltage).
5.2. The Transmission Operator shall provide the Generator Operator with the notification
requirements for deviations from the voltage or Reactive Power schedule (which is either a
range or a target value with an associated tolerance band).
5.3. The Transmission Operator shall provide the criteria used to develop voltage schedules or
Reactive Power schedule (which is either a range or a target value with an associated
tolerance band) to the Generator Operator within 30 days of receiving a request.
M5. The Transmission Operator shall have evidence of a documented voltage or Reactive Power
schedule (which is either a range or a target value with an associated tolerance band).
For part 5.1, the Transmission Operator shall have evidence it provided a voltage or Reactive Power
schedule (which is either a range or a target value with an associated tolerance band) to the
applicable Generator Operators, and that the Generator Operator was directed to comply with the
schedule in automatic voltage control mode, unless exempted.
For part 5.2, the Transmission Operator shall have evidence it provided notification requirements
for deviations from the voltage or Reactive Power schedule (which is either a range or a target
value with an associated tolerance band). For part 5.3, the Transmission Operator shall have
evidence it provided the criteria used to develop voltage schedules or Reactive Power schedule
(which is either a range or a target value with an associated tolerance band) within 30 days of
receiving a request by a Generator Operator.
R6. After consultation with the Generator Owner regarding necessary step-up transformer tap changes
and the implementation schedule, the Transmission Operator shall provide documentation to the
Generator Owner specifying the required tap changes, a timeframe for making the changes, and
technical justification for these changes. [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
M6. The Transmission Operator shall have evidence that it provided documentation to the Generator
Owner when a change was needed to a generating unit’s step-up transformer tap in accordance
with the requirement and that it consulted with the Generator Owner.

Page 3 of 15

VAR-001-4.2 — Voltage and Reactive Control

C. Compliance
1.

Compliance Monitoring Process:

1.1. Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” refers to NERC or
the Regional Entity in their respective roles of monitoring and enforcing compliance with the NERC
Reliability Standards.
1.2. Evidence Retention:
The following evidence retention periods identify the period of time a registered entity is required
to retain specific evidence to demonstrate compliance. For instances in which the evidence
retention period specified below is shorter than the time since the last audit, the Compliance
Enforcement Authority may ask the registered entity to provide other evidence to show that it was
compliant for the full time period since the last audit.
The Transmission Operator shall retain evidence for Measures M1 through M6 for 12 months. The
Compliance Monitor shall retain any audit data for three years.
1.3. Compliance Monitoring and Assessment Processes:
“Compliance Monitoring and Assessment Processes” refers to the identification of the processes
that will be used to evaluate data or information for the purpose of assessing performance or
outcomes with the associated reliability standard.
1.4. Additional Compliance Information:
None

Page 4 of 15

VAR-001-4.2 — Voltage and Reactive Control
Table of Compliance Elements
R#

Time
Horizon

Operations
Planning

Real-time
Operations,
Same-day
Operations,
and
Operations
Planning

VRF

High

Violation Severity Levels

Lower VSL

N/A

Moderate VSL

High VSL

Severe VSL

N/A

The Transmission
Operator does not
specify a system
voltage schedule
(which is either a
range or a target
value with an
associated tolerance
band).

N/A

The Transmission
Operator does not
schedule sufficient
reactive resources as
necessary to avoid
violating an SOL.

The Transmission
Operator does not
schedule sufficient
reactive resources as
necessary to avoid
violating an IROL.

N/A

The Transmission
Operator does not
operate or direct any
real-time operation
of devices as
necessary to avoid
violating an SOL.

The Transmission
Operator does not
operate or direct any
real-time operation of
devices as necessary
to avoid violating an
IROL.

Page 5 of 15

VAR-001-4.2 — Voltage and Reactive Control

Time
Horizon

Operations
Planning

VRF

Lower

Violation Severity Levels

Lower VSL

N/A

Moderate VSL

High VSL

N/A

The Transmission
Operator has
exemption criteria
and notified the
Generator Operator,
but the Transmission
Operator does not
have evidence of the
notification to the
Generator Operator.

Severe VSL

The Transmission
Operator does not
have exemption
criteria.

Page 6 of 15

VAR-001-4.2 — Voltage and Reactive Control

Time
Horizon

Operations
Planning

VRF

Medium

Violation Severity Levels

Lower VSL

N/A

Moderate VSL

The Transmission
Operator does not
provide the criteria
for voltage or
Reactive Power
schedules (which is
either a range or a
target value with an
associated tolerance
band) after 30 days
of a request.

High VSL

The Transmission
Operator does not
provide voltage or
Reactive Power
schedules (which is
either a range or a
target value with an
associated tolerance
band) to all
Generator
Operators.

Severe VSL
The Transmission
Operator does not
provide voltage or
Reactive Power
schedules (which is
either a range or a
target value with an
associated tolerance
band) to any
Generator Operators.
Or
The Transmission
Operator does not
provide the
Generator Operator
with the notification
requirements for
deviations from the
voltage or Reactive
Power schedule
(which is either a
range or a target
value with an
associated tolerance
band).

Page 7 of 15

VAR-001-4.2 — Voltage and Reactive Control

Time
Horizon

Operations
Planning

VRF

Lower

Violation Severity Levels

Lower VSL
The Transmission
Operator does not
provide either the
technical justification
or timeframe for
changing generator
step-up tap settings.

Moderate VSL

N/A

High VSL

Severe VSL

N/A

The Transmission
Operator does not
provide the technical
justification and the
timeframe for
changing generator
step-up tap settings.

Page 8 of 15

VAR-001-4.2 Application Guidelines

D. Regional Variances
The following Interconnection-wide variance shall be applicable in the Western Electricity Coordinating
Council (WECC) and replaces, in their entirety, Requirements R4 and R5. Please note that Requirement
R4 is deleted and R5 is replaced with the following requirements.
Requirements
E.A.13

E.A.14

Each Transmission Operator shall issue any one of the following types of voltage schedules to
the Generator Operators for each of their generation resources that are on-line and part of
the Bulk Electric System within the Transmission Operator Area: [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning and Same-day Operations]
•

A voltage set point with a voltage tolerance band and a specified period.

•

An initial volt-ampere reactive output or initial power factor output with a voltage
tolerance band for a specified period that the Generator Operator uses to establish a
generator bus voltage set point.

•

A voltage band for a specified period.

Each Transmission Operator shall provide one of the following voltage schedule reference
points for each generation resource in its Area to the Generator Operator. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning and Same-day Operations]
•

The generator terminals.

•

The high side of the generator step-up transformer.

•

The point of interconnection.

•

A location designated by mutual agreement between the Transmission Operator and
Generator Operator.

E.A.15

Each Generator Operator shall convert each voltage schedule specified in Requirement E.A.13
into the voltage set point for the generator excitation system. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning and Same-day Operations]

E.A.16

Each Generator Operator shall provide its voltage set point conversion methodology from the
point in Requirement E.A.14 to the generator terminals within 30 calendar days of request by
its Transmission Operator. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

E.A.17

Each Transmission Operator shall provide to the Generator Operator, within 30 calendar days
of a request for data by the Generator Operator, its transmission equipment data and
operating data that supports development of the voltage set point conversion methodology.
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

E.A.18

Each Generator Operator shall meet the following control loop specifications if the Generator
Operator uses control loops external to the automatic voltage regulators (AVR) to manage
Mvar loading: [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]

E.A.18.1. Each control loop’s design incorporates the AVR’s automatic voltage controlled response to
voltage deviations during System Disturbances.
E.A.18.2. Each control loop is only used by mutual agreement between the Generator Operator and the
Transmission Operator affected by the control loop.
Page 9 of 15

VAR-001-4.2 Application Guidelines
Measures 1
M.E.A.13 Each Transmission Operator shall have and provide upon request, evidence that it provided
the voltage schedules to the Generator Operator. Dated spreadsheets, reports, voice
recordings, or other documentation containing the voltage schedule including set points,
tolerance bands, and specified periods as required in Requirement E.A.13 are acceptable as
evidence.
M.E.A.14 The Transmission Operator shall have and provide upon request, evidence that it provided
one of the voltage schedule reference points in Requirement E.A.14 for each generation
resource in its Area to the Generator Operator. Dated letters, e-mail, or other documentation
that contains notification to the Generator Operator of the voltage schedule reference point
for each generation resource are acceptable as evidence.
M.E.A.15 Each Generator Operator shall have and provide upon request, evidence that it converted a
voltage schedule as described in Requirement E.A.13 into a voltage set point for the AVR.
Dated spreadsheets, logs, reports, or other documentation are acceptable as evidence.
M.E.A.16 The Generator Operator shall have and provide upon request, evidence that within 30
calendar days of request by its Transmission Operator it provided its voltage set point
conversion methodology from the point in Requirement E.A.14 to the generator terminals.
Dated reports, spreadsheets, or other documentation are acceptable as evidence.
M.E.A.17 The Transmission Operator shall have and provide upon request, evidence that within 30
calendar days of request by its Generator Operator it provided data to support development
of the voltage set point conversion methodology. Dated reports, spreadsheets, or other
documentation are acceptable as evidence.
M.E.A.18 If the Generator Operator uses outside control loops to manage Mvar loading, the Generator
Operator shall have and provide upon request, evidence that it met the control loop
specifications in sub-parts E.A.18.1 through E.A.18.2. Design specifications with identified
agreed-upon control loops, system reports, or other dated documentation are acceptable as
evidence.

The number for each measure corresponds with the number for each requirement, i.e. M.E.A.13 means the measure for Requirement E.A.13.

Page 10 of 15

VAR-001-4.2 Application Guidelines

Violation Severity Levels
E#

Lower VSL

Moderate VSL

High VSL

Severe VSL

E.A.13

For the specified
period, the
Transmission
Operator did not
issue one of the
voltage schedules
listed in E.A.13 to at
least one
generation resource
but less than or
equal to 5% of the
generation
resources that are
on-line and part of
the BES in the
Transmission
Operator Area.

For the specified
period, the
Transmission
Operator did not
issue one of the
voltage schedules
listed in E.A.13 to
more than 5% but
less than or equal to
10% of the
generation
resources that are
on-line and part of
the BES in the
Transmission
Operator Area.

For the specified
period, the
Transmission
Operator did not
issue one of the
voltage schedules
listed in E.A.13 to
more than 10% but
less than or equal to
15% of the
generation
resources that are
on-line and part of
the BES in the
Transmission
Operator Area.

For the specified
period, the
Transmission
Operator did not
issue one of the
voltage schedules
listed in E.A.13 to
more than 15% of
the generation
resources that are
on-line and part of
the BES in the
Transmission
Operator Area.

E.A.14

The Transmission
Operator did not
provide a voltage
schedule reference
point for at least
one but less than or
equal to 5% of the
generation
resources in the
Transmission
Operator area.

The Transmission
Operator did not
provide a voltage
schedule reference
point for more than
5% but less than or
equal to 10% of the
generation
resources in the
Transmission
Operator Area.

The Transmission
Operator did not a
voltage schedule
reference point for
more than 10% but
less than or equal to
15% of the
generation
resources in the
Transmission
Operator Area.

The Transmission
Operator did not
provide a voltage
schedule reference
point for more than
15% of the
generation
resources in the
Transmission
Operator Area.

E.A.15

The Generator
Operator failed to
convert at least one
voltage schedule in
Requirement E.A.13
into the voltage set
point for the AVR
for less than 25% of
the voltage
schedules.

The Generator
Operator failed to
convert the voltage
schedules in
Requirement E.A.13
into the voltage set
point for the AVR
for 25% or more but
less than 50% of the
voltage schedules.

The Generator
Operator failed to
convert the voltage
schedules in
Requirement E.A.13
into the voltage set
point for the AVR
for 50% or more but
less than 75% of the
voltage schedules.

The Generator
Operator failed to
convert the voltage
schedules in
Requirement E.A.13
into the voltage set
point for the AVR
for 75% or more of
the voltage
schedules.

Page 11 of 15

VAR-001-4.2 Application Guidelines
E#

Lower VSL

Moderate VSL

High VSL

Severe VSL

E.A.16

The Generator
Operator provided
its voltage set
point conversion
methodology
greater than 30
days but less than
or equal to 60
days of a request
by the
Transmission
Operator.

The Generator
Operator provided
its voltage set
point conversion
methodology
greater than 60
days but less than
or equal to 90
days of a request
by the
Transmission
Operator.

The Generator
Operator provided
its voltage set
point conversion
methodology
greater than 90
days but less than
or equal to 120
days of a request
by the
Transmission
Operator.

The Generator
Operator did not
provide its
voltage set point
conversion
methodology
within 120 days of
a request by the
Transmission
Operator.

E.A.17

The Transmission
Operator provided
its data to support
development of
the voltage set
point conversion
methodology than
30 days but less
than or equal to
60 days of a
request by the
Generator
Operator.

The Transmission
Operator provided
its data to support
development of
the voltage set
point conversion
methodology
greater than 60
days but less than
or equal to 90
days of a request
by the Generator.
Operator.

The Transmission
Operator provided
its data to support
development of
the voltage set
point conversion
methodology
greater than 90
days but less than
or equal to 120
days of a request
by the Generator.
Operator.

The Transmission
Operator did not
provide its data to
support
development of
the voltage set
point conversion
methodology
within 120 days of
a request by the
Generator
Operator.

N/A

The Generator
Operator did not
meet the control
loop specifications
in EA18.2 when the
Generator Operator
uses control loop
external to the AVR
to manage Mvar
loading.

The Generator
Operator did not
meet the control
loop specifications
in EA18.1 when the
Generator Operator
uses control loop
external to the AVR
to manage Mvar
loading.

The Generator
Operator did not
meet the control
loop specifications
in EA18.1 through
EA18.2 when the
Generator Operator
uses control loop
external to the AVR
to manage Mvar
loading.

E.A.18

Interpretations
None

Page 12 of 15

VAR-001-4.2 Application Guidelines
F.

Associated Documents
None.

Version History
Version

Date

Action

Change Tracking

April 1, 2005

Effective Date

New

August 2, 2006

BOT Adoption

Revised

June 18, 2007

FERC approved Version 1 of the standard.

Revised

July 3, 2007

Added “Generator Owners” and “Generator
Operators” to Applicability section.

Errata

August 23, 2007

Removed “Generator Owners” and “Generator
Operators” to Applicability section.

Errata

August 5, 2010

Adopted by NERC Board of Trustees; Modified to
address Order No. 693 Directives contained in
paragraphs 1858 and 1879.

Revised

January, 10 2011

FERC issued letter order
approving the addition of LSEs
and Controllable Load to the
standard.

Revised

May 9, 2012

Adopted by NERC Board of Trustees; Modified to
add a WECC region variance

Revised

June 20, 2013

FERC issued order approving VAR-001-3

Revised

November 21,
2013

R5 and associated elements approved by FERC for
retirement as part of the Paragraph 81 project
(Project 2013-02)

Revised

February 6, 2014 Adopted by NERC Board of Trustees

August 1, 2014

4.1

August 25, 2015

4.1

November 13,
2015
June 14, 2017
August 10, 2017

4.2
4.2

FERC issued letter order issued approving VAR001-4
Added “or” to Requirement R5, 5.3 to read:
schedules or Reactive Power
FERC Letter Order approved errata to VAR-001-4.1.
Docket RD15-6-000
Project 2016-EPR-02 errata recommendations
Adopted by NERC Board of Trustees

Revised

Errata
Errata
Errata
Errata

Page 13 of 15

VAR-001-4.2 Application Guidelines
Guidelines and Technical Basis
For technical basis for each requirement, please review the rationale provided for each requirement.
Rationale:

During development of this standard, text boxes were embedded within the standard to explain the rationale
for various parts of the standard. Upon BOT approval, the text from the rationale text boxes was moved to this
section.
Rationale for R1:
Paragraph 1868 of Order No. 693 requires NERC to add more "detailed and definitive requirements on
“established limits” and “sufficient reactive resources”, and identify acceptable margins (i.e. voltage and/or
reactive power margins)." Since Order No. 693 was issued, however, several FAC and TOP standards have
become enforceable to add more requirements around voltage limits. More specifically, FAC-011 and FAC-014
require that System Operating Limits (SOLs) and reliability margins are established. The NERC Glossary
definition of SOLs includes both: 1) voltage stability ratings (Applicable pre- and post-Contingency Voltage
Stability) and 2) System Voltage Limits (Applicable pre- and post-Contingency voltage limits). Therefore, for
reliability reasons Requirement R1 now requires a Transmission Operator (TOP) to set voltage or Reactive
Power schedules with associated tolerance bands. Further, since neighboring areas can affect each other
greatly, each TOP must also provide a copy of these schedules to its Reliability Coordinator (RC) and adjacent
TOP upon request.
Rationale for R2:
Paragraph 1875 from Order No. 693 directed NERC to include requirements to run voltage stability analysis
periodically, using online techniques where commercially available and offline tools when online tools are not
available. This standard does not explicitly require the periodic voltage stability analysis because such analysis
would be performed pursuant to the SOL methodology developed under the FAC standards. TOP standards
also require the TOP to operate within SOLs and Interconnection Reliability Operating Limits (IROL). The VAR
standard drafting team (SDT) and industry participants also concluded that the best models and tools are the
ones that have been proven and the standard should not add a requirement for a responsible entity to
purchase new online simulations tools. Thus, the VAR SDT simplified the requirements to ensuring sufficient
reactive resources are online or scheduled. Controllable load is specifically included to answer FERC's directive
in Order No. 693 at Paragraph 1879.
Rationale for R3:
Similar to Requirement R2, the VAR SDT determined that for reliability purposes, the TOP must ensure
sufficient voltage support is provided in Real-time in order to operate within an SOL.
Rationale for R4:
The VAR SDT received significant feedback on instances when a TOP would need the flexibility for defining
exemptions for generators. These exemptions can be tailored as the TOP deems necessary for the specific
Page 14 of 15

VAR-001-4.2 Application Guidelines
area’s needs. The goal of this requirement is to provide a TOP the ability to exempt a Generator Operator
(GOP) from: 1) a voltage or Reactive Power schedule, 2) a setting on the AVR, or 3) any VAR-002 notifications
based on the TOP’s criteria. Feedback from the industry detailed many system events that would require these
types of exemptions which included, but are not limited to: 1) maintenance during shoulder months, 2)
scenarios where two units are located within close proximity and both cannot be in voltage control mode, and
3) large system voltage swings where it would harm reliability if all GOP were to notify their respective TOP of
deviations at one time. Also, in an effort to improve the requirement, the sub-requirements containing an
exemption list were removed from the currently enforceable standard because this created more compliance
issues with regard to how often the list would be updated and maintained.
Rationale for R5:
The new requirement provides transparency regarding the criteria used by the TOP to establish the voltage
schedule. This requirement also provides a vehicle for the TOP to use appropriate granularity when setting
notification requirements for deviation from the voltage or Reactive Power schedule. Additionally, this
requirement provides clarity regarding a “tolerance band” as specified in the voltage schedule and the control
dead-band in the generator’s excitation system.
Voltage schedule tolerances are the bandwidth that accompanies the voltage target in a voltage schedule,
should reflect the anticipated fluctuation in voltage at the Generation Operator’s facility during normal
operations, and be based on the TOP’s assessment of N‐1 and credible N‐2 system contingencies. The voltage
schedule’s bandwidth should not be confused with the control dead‐band that is programmed into a
Generation Operator’s automatic voltage regulator’s control system, which should be adjusting the AVR prior
to reaching either end of the voltage schedule’s bandwidth.
Rationale for R6:
Although tap settings are first established prior to interconnection, this requirement could not be deleted
because no other standard addresses when a tap setting must be adjusted. If the tap setting is not properly
set, then the amount of VARs produced by a unit can be affected.

Page 15 of 15

Exhibit A-2
Proposed Reliability Standard VAR-001-4.2 Redline

VAR-001-4.1 2 — Voltage and Reactive Control

A. Introduction
1.

Title:

Number: VAR-001-4.12

Applicability:

Voltage and Reactive Control

4.1. Transmission Operators
4.2. Generator Operators within the Western Interconnection (for the WECC Variance)
5.

Page 1 of 17

VAR-001-4.1 2 — Voltage and Reactive Control

B. Requirements and Measures
R1. Each Transmission Operator shall specify a system voltage schedule (which is either a range or a
target value with an associated tolerance band) as part of its plan to operate within System
Operating Limits and Interconnection Reliability Operating Limits. [Violation Risk Factor: High]
[Time Horizon: Operational Operations Planning]
1.1. Each Transmission Operator shall provide a copy of the voltage schedules (which is either a
range or a target value with an associated tolerance band) to its Reliability Coordinator and
adjacent Transmission Operators within 30 calendar days of a request.
M1. The Transmission Operator shall have evidence that it specified system voltage schedules using
either a range or a target value with an associated tolerance band.
For part 1.1, the Transmission Operator shall have evidence that the voltage schedules (which is
either a range or a target value with an associated tolerance band) were provided to its Reliability
Coordinator and adjacent Transmission Operators within 30 calendar days of a request. Evidence
may include, but is not limited to, emails, website postings, and meeting minutes.
R2. Each Transmission Operator shall schedule sufficient reactive resources to regulate voltage levels
under normal and Contingency conditions. Transmission Operators can provide sufficient reactive
resources through various means including, but not limited to, reactive generation scheduling,
transmission line and reactive resource switching, and using controllable load. [Violation Risk
Factor: High] [Time Horizon: Real-time Operations, Same-day Operations, and Operational
Operations Planning]
M2. Each Transmission Operator shall have evidence of scheduling sufficient reactive resources based
on their assessments of the system. For the operational operations planning time horizon,
Transmission Operators shall have evidence of assessments used as the basis for how resources
were scheduled.
R3. Each Transmission Operator shall operate or direct the Real-time operation of devices to regulate
transmission voltage and reactive flow as necessary. [Violation Risk Factor: High] [Time Horizon:
Real-time Operations, Same-day Operations, and Operational Operations Planning]
M3. Each Transmission Operator shall have evidence that actions were taken to operate capacitive and
inductive resources as necessary in Real-time. This may include, but is not limited to, instructions to
Generator Operators to: 1) provide additional voltage support; 2) bring resources on-line; or 3)
make manual adjustments.
R4. The Each Transmission Operator shall specify the criteria that will exempt generators from: 1) from
following a voltage or Reactive Power schedule, 2) from having its automatic voltage regulator
(AVR) in service or from being in voltage control mode, or 3) from having to make any associated
notifications. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
4.1 If a Transmission Operator determines that a generator has satisfied the exemption criteria, it
shall notify the associated Generator Operator.
M4. Each Transmission Operator shall have evidence of the documented criteria for generator
exemptions.

Page 2 of 17

VAR-001-4.1 2 — Voltage and Reactive Control
For part 4.1, the Transmission Operator shall also have evidence to show that, for each generator in
its area that is exempt from: 1) from following a voltage or Reactive Power schedule, 2) from
having its automatic voltage regulator (AVR) in service or from being in voltage control mode, or 3)
from having to make any notifications, the associated Generator Operator was notified of this
exemption.
R5. Each Transmission Operator shall specify a voltage or Reactive Power schedule (which is either a
range or a target value with an associated tolerance band) at either the high voltage side or low
voltage side of the generator step-up transformer at the Transmission Operator’s discretion.
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning]
5.1. The Transmission Operator shall provide the voltage or Reactive Power schedule (which is
either a range or a target value with an associated tolerance band) to the associated
Generator Operator and direct the Generator Operator to comply with the schedule in
automatic voltage control mode (the AVR is in service and controlling voltage).
5.2. The Transmission Operator shall provide the Generator Operator with the notification
requirements for deviations from the voltage or Reactive Power schedule (which is either a
range or a target value with an associated tolerance band).
5.3. The Transmission Operator shall provide the criteria used to develop voltage schedules or
Reactive Power schedule (which is either a range or a target value with an associated
tolerance band) to the Generator Operator within 30 days of receiving a request.
M5. The Transmission Operator shall have evidence of a documented voltage or Reactive Power
Schedule schedule (which is either a range or a target value with an associated tolerance band).
For part 5.1, the Transmission Operator shall have evidence it provided a voltage or Reactive Power
schedule (which is either a range or a target value with an associated tolerance band) to the
applicable Generator Operators, and that the Generator Operator was directed to comply with the
schedule in automatic voltage control mode, unless exempted.
For part 5.2, the Transmission Operator shall have evidence it provided notification requirements
for deviations from the voltage or Reactive Power schedule (which is either a range or a target
value with an associated tolerance band). For part 5.3, the Transmission Operator shall have
evidence it provided the criteria used to develop voltage schedules or Reactive Power schedule
(which is either a range or a target value with an associated tolerance band) within 30 days of
receiving a request by a Generator Operator.
R6. After consultation with the Generator Owner regarding necessary step-up transformer tap changes
and the implementation schedule, the Transmission Operator shall provide documentation to the
Generator Owner specifying the required tap changes, a timeframe for making the changes, and
technical justification for these changes. [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
M6. The Transmission Operator shall have evidence that it provided documentation to the Generator
Owner when a change was needed to a generating unit’s step-up transformer tap in accordance
with the requirement and that it consulted with the Generator Owner.

Page 3 of 17

VAR-001-4.1 2 — Voltage and Reactive Control

C. Compliance
1.

Compliance Monitoring Process:

Page 4 of 17

VAR-001-4.1 2 — Voltage and Reactive Control
Table of Compliance Elements
R#

Time
Horizon

Operational
Operations
Planning

Real-time
Operations,
Same-day
Operations,
and
Operational
Operations
Planning

VRF

High

Violation Severity Levels

Lower VSL

N/A

Moderate VSL

High VSL

Severe VSL

N/A

The Transmission
Operator does not
specify a system
voltage schedule
(which is either a
range or a target
value with an
associated tolerance
band).

N/A

The Transmission
Operator does not
schedule sufficient
reactive resources as
necessary to avoid
violating an SOL.

The Transmission
Operator does not
schedule sufficient
reactive resources as
necessary to avoid
violating an IROL.

N/A

The Transmission
Operator does not
operate or direct any
real-time operation
of devices as
necessary to avoid
violating an SOL.

The Transmission
Operator does not
operate or direct any
real-time operation of
devices as necessary
to avoid violating an
IROL.

Page 5 of 17

VAR-001-4.1 2 — Voltage and Reactive Control

Time
Horizon

Operations
Planning

VRF

Lower

Violation Severity Levels

Lower VSL

N/A

Moderate VSL

High VSL

N/A

The Transmission
Operator has
exemption criteria
and notified the
Generator Operator,
but the Transmission
Operator does not
have evidence of the
notification to the
Generator Operator.

Severe VSL

The Transmission
Operator does not
have exemption
criteria.

Page 6 of 17

VAR-001-4.1 2 — Voltage and Reactive Control

Time
Horizon

Operations
Planning

VRF

Medium

Violation Severity Levels

Lower VSL

N/A

Moderate VSL

High VSL

The Transmission
Operator does not
provide voltage or
Reactive Power
schedules (which is
either a range or a
target value with an
associated tolerance
band) to all
Generator
Operators.

Page 7 of 17

VAR-001-4.1 2 — Voltage and Reactive Control

Time
Horizon

Operations
Planning

VRF

Lower

Violation Severity Levels

Lower VSL
The Transmission
Operator does not
provide either the
technical justification
or timeframe for
changing generator
step-up tap settings.

Moderate VSL

N/A

High VSL

Severe VSL

N/A

The Transmission
Operator does not
provide the technical
justification and the
timeframe for
changing generator
step-up tap settings.

Page 8 of 17

VAR-001-4.2 Application Guidelines

E.A.14

A voltage set point with a voltage tolerance band and a specified period.

•

A voltage band for a specified period.

The generator terminals.

•

The high side of the generator step-up transformer.

•

The point of interconnection.

•

A location designated by mutual agreement between the Transmission Operator and
Generator Operator.

E.A.15

E.A.16

E.A.17

E.A.18

Each Generator Operator shall meet the following control loop specifications if the Generator
Operator uses control loops external to the Automatic Voltage Regulatorsautomatic voltage
regulators (AVR) to manage MVar Mvar loading: [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations]

E.A.18.1. Each control loop’s design incorporates the AVR’s automatic voltage controlled response to
voltage deviations during System Disturbances.
Page 9 of 17

VAR-001-4.2 Application Guidelines
E.A.18.2. Each control loop is only used by mutual agreement between the Generator Operator and the
Transmission Operator affected by the control loop.
Measures 1
M.E.A.13 Each Transmission Operator shall have and provide upon request, evidence that it provided
the voltage schedules to the Generator Operator. Dated spreadsheets, reports, voice
recordings, or other documentation containing the voltage schedule including set points,
tolerance bands, and specified periods as required in Requirement E.A.13 are acceptable as
evidence.
M.E.A.14 The Transmission Operator shall have and provide upon request, evidence that it provided
one of the voltage schedule reference points in Requirement E.A.14 for each generation
resource in its Area to the Generator Operator. Dated letters, e-mail, or other documentation
that contains notification to the Generator Operator of the voltage schedule reference point
for each generation resource are acceptable as evidence.
M.E.A.15 Each Generator Operator shall have and provide upon request, evidence that it converted a
voltage schedule as described in Requirement E.A.13 into a voltage set point for the AVR.
Dated spreadsheets, logs, reports, or other documentation are acceptable as evidence.
M.E.A.16 The Generator Operator shall have and provide upon request, evidence that within 30
calendar days of request by its Transmission Operator it provided its voltage set point
conversion methodology from the point in Requirement E.A.14 to the generator terminals.
Dated reports, spreadsheets, or other documentation are acceptable as evidence.
M.E.A.17 The Transmission Operator shall have and provide upon request, evidence that within 30
calendar days of request by its Generator Operator it provided data to support development
of the voltage set point conversion methodology. Dated reports, spreadsheets, or other
documentation are acceptable as evidence.
M.E.A.18 If the Generator Operator uses outside control loops to manage MVar Mvar loading, the
Generator Operator shall have and provide upon request, evidence that it met the control
loop specifications in sub-parts E.A.18.1 through E.A.18.2. Design specifications with
identified agreed-upon control loops, system reports, or other dated documentation are
acceptable as evidence.

The number for each measure corresponds with the number for each requirement, i.e. M.E.A.13 means the measure for Requirement E.A.13.

Page 10 of 17

VAR-001-4.2 Application Guidelines

Violation Severity Levels
E#

Lower VSL

Moderate VSL

High VSL

Severe VSL

E.A.13

E.A.14

The Transmission
Operator did not
provide a voltage
schedule reference
point for at least
one but less than or
equal to 5% of the
generation
resources in the
Transmission
Operator area.

The Transmission
Operator did not
provide a voltage
schedule reference
point for more than
5% but less than or
equal to 10% of the
generation
resources in the
Transmission
Operator Area.

The Transmission
Operator did not a
voltage schedule
reference point for
more than 10% but
less than or equal to
15% of the
generation
resources in the
Transmission
Operator Area.

The Transmission
Operator did not
provide a voltage
schedule reference
point for more than
15% of the
generation
resources in the
Transmission
Operator Area.

E.A.15

The Generator
Operator failed to
convert at least one
voltage schedule in
Requirement E.A.13
into the voltage set
point for the AVR
for less than 25% of
the voltage
schedules.

The Generator
Operator failed to
convert the voltage
schedules in
Requirement E.A.13
into the voltage set
point for the AVR
for 25% or more but
less than 50% of the
voltage schedules.

The Generator
Operator failed to
convert the voltage
schedules in
Requirement E.A.13
into the voltage set
point for the AVR
for 50% or more but
less than 75% of the
voltage schedules.

The Generator
Operator failed to
convert the voltage
schedules in
Requirement E.A.13
into the voltage set
point for the AVR
for 75% or more of
the voltage
schedules.

Page 11 of 17

VAR-001-4.2 Application Guidelines
E#

Lower VSL

Moderate VSL

High VSL

Severe VSL

E.A.16

The Generator
Operator provided
its voltage set
point conversion
methodology
greater than 30
days but less than
or equal to 60
days of a request
by the
Transmission
Operator.

The Generator
Operator provided
its voltage set
point conversion
methodology
greater than 60
days but less than
or equal to 90
days of a request
by the
Transmission
Operator.

The Generator
Operator provided
its voltage set
point conversion
methodology
greater than 90
days but less than
or equal to 120
days of a request
by the
Transmission
Operator.

The Generator
Operator did not
provide its
voltage set point
conversion
methodology
within 120 days of
a request by the
Transmission
Operator.

E.A.17

The Transmission
Operator did not
provide its data to
support
development of
the voltage set
point conversion
methodology
within 120 days of
a request by the
Generator
Operator.

N/A

The Generator
Operator did not
meet the control
loop specifications
in EA18.2 when the
Generator Operator
uses control loop
external to the AVR
to manage Mvar
loading.

The Generator
Operator did not
meet the control
loop specifications
in EA18.1 when the
Generator Operator
uses control loop
external to the AVR
to manage Mvar
loading.

The Generator
Operator did not
meet the control
loop specifications
in EA18.1 through
EA18.2 when the
Generator Operator
uses control loop
external to the AVR
to manage Mvar
loading.

E.A.18

Interpretations
None

Page 12 of 17

VAR-001-4.2 Application Guidelines
F.

Associated Documents
None.

Version History
Version

Date

Action

Change Tracking

April 1, 2005

Effective Date

New

August 2, 2006

BOT Adoption

Revised

June 18, 2007

FERC approved Version 1 of the
standard.

Revised

July 3, 2007

Added “Generator Owners” and
“Generator Operators” to Applicability
section.

Errata

August 23, 2007

Removed “Generator Owners” and
“Generator Operators” to Applicability
section.

Errata

August 5, 2010

Adopted by NERC Board of Trustees;
Revised
Modified to address Order No. 693
Directives contained in paragraphs 1858
and 1879.

January, 10
2011

FERC issued letter order
approving the addition of LSEs
and Controllable Load to the
standard.

Revised

May 9, 2012

Adopted by NERC Board of Trustees;
Modified to add a WECC region
variance

Revised

June 20, 2013

FERC issued order approving VAR-001-3

Revised

November 21,
2013

R5 and associated elements approved
by FERC for retirement as part of the
Paragraph 81 project (Project 2013-02)

Revised

Adopted by NERC Board of Trustees

Revised

February 6,
2014
August 1, 2014

4.1

August 25, 2015

4.1

November 13,
2015
June 14, 2017

4.2

FERC issued letter order issued
approving VAR-001-4
Added “or” to Requirement R5, 5.3 to
read: schedules or Reactive Power
FERC Letter Order approved errata to
VAR-001-4.1. Docket RD15-6-000
Project 2016-EPR-02 errata
recommendations

Errata
Errata
Errata
Page 13 of 17

VAR-001-4.2 Application Guidelines
4.2

August 10, 2017

FERC Adopted by NERC Board of
Trustees

Errata

Page 14 of 17

VAR-001-4.2 Application Guidelines
Guidelines and Technical Basis
For technical basis for each requirement, please review the rationale provided for each requirement.
Rationale:

During development of this standard, text boxes were embedded within the standard to explain the rationale
for various parts of the standard. Upon BOT approval, the text from the rationale text boxes was moved to this
section.
Rationale for R1:
Paragraph 1868 of Order No. 693 requires NERC to add more "detailed and definitive requirements on
“established limits” and “sufficient reactive resources”, and identify acceptable margins (i.e. voltage and/or
reactive power margins)." Since Order No. 693 was issued, however, several FAC and TOP standards have
become enforceable to add more requirements around voltage limits. More specifically, FAC-011 and FAC-014
require that System Operating Limits (SOLs) and reliability margins are established. The NERC Glossary
definition of SOLs includes both: 1) Voltage Stability Ratingsvoltage stability ratings (Applicable pre- and postContingency Voltage Stability) and 2) System Voltage Limits (Applicable pre- and post-Contingency Voltage
Limitsvoltage limits). Therefore, for reliability reasons Requirement R1 now requires a Transmission Operator
(TOP) to set voltage or Reactive Power schedules with associated tolerance bands. Further, since neighboring
areas can affect each other greatly, each TOP must also provide a copy of these schedules to its Reliability
Coordinator (RC) and adjacent TOP upon request.
Rationale for R2:
Paragraph 1875 from Order No. 693 directed NERC to include requirements to run voltage stability analysis
periodically, using online techniques where commercially available and offline tools when online tools are not
available. This standard does not explicitly require the periodic voltage stability analysis because such analysis
would be performed pursuant to the SOL methodology developed under the FAC standards. TOP standards
also require the TOP to operate within SOLs and Interconnection Reliability Operating Limits (IROL). The VAR
standard drafting team (SDT) and industry participants also concluded that the best models and tools are the
ones that have been proven and the standard should not add a requirement for a responsible entity to
purchase new online simulations tools. Thus, the VAR SDT simplified the requirements to ensuring sufficient
reactive resources are online or scheduled. Controllable load is specifically included to answer FERC's directive
in Order No. 693 at Paragraph 1879.
Rationale for R3:
Similar to Requirement R2, the VAR SDT determined that for reliability purposes, the TOP must ensure
sufficient voltage support is provided in Real-time in order to operate within an SOL.
Rationale for R4:
The VAR SDT received significant feedback on instances when a TOP would need the flexibility for defining
exemptions for generators. These exemptions can be tailored as the TOP deems necessary for the specific
Page 15 of 17

VAR-001-4.2 Application Guidelines
area’s needs. The goal of this requirement is to provide a TOP the ability to exempt a Generator Operator
(GOP) from: 1) a voltage or Reactive Power schedule, 2) a setting on the AVR, or 3) any VAR-002 notifications
based on the TOP’s criteria. Feedback from the industry detailed many system events that would require these
types of exemptions which included, but are not limited to: 1) maintenance during shoulder months, 2)
scenarios where two units are located within close proximity and both cannot be in voltage control mode, and
3) large system voltage swings where it would harm reliability if all GOP were to notify their respective TOP of
deviations at one time. Also, in an effort to improve the requirement, the sub-requirements containing an
exemption list were removed from the currently enforceable standard because this created more compliance
issues with regard to how often the list would be updated and maintained.
Rationale for R5:
The new requirement provides transparency regarding the criteria used by the TOP to establish the voltage
schedule This requirement also provides a vehicle for the TOP to use appropriate granularity when setting
notification requirements for deviation from the voltage or Reactive Power schedule. Additionally, this
requirement provides clarity regarding a “tolerance band” as specified in the voltage schedule and the control
dead-band in the generator’s excitation system.
Voltage Schedule schedule tolerances are the bandwidth that accompanies the voltage target in a voltage
schedule, should reflect the anticipated fluctuation in voltage at the Generation Operator’s facility during
normal operations, and be based on the TOP’s assessment of N‐1 and credible N‐2 system contingencies. The
voltage schedule’s bandwidth should not be confused with the control dead‐band that is programmed into a
Generation Operator’s automatic voltage regulator’s control system, which should be adjusting the AVR prior
to reaching either end of the voltage schedule’s bandwidth.
Rationale for R6:
Although tap settings are first established prior to interconnection, this requirement could not be deleted
because no other standard addresses when a tap setting must be adjusted. If the tap setting is not properly
set, then the amount of VARs produced by a unit can be affected.
Version History
Version

Date

Action

Change Tracking

April 1, 2005

Effective Date

New

August 2, 2006

BOT Adoption

Revised

June 18, 2007

FERC approved Version 1 of the
standard.

Revised

July 3, 2007

Added “Generator Owners” and
“Generator Operators” to Applicability
section.

Errata

August 23,
2007

Removed “Generator Owners” and
“Generator Operators” to Applicability
section.

Errata

Page 16 of 17

VAR-001-4.2 Application Guidelines
2

August 5, 2010

Adopted by NERC Board of Trustees;
Revised
Modified to address Order No. 693
Directives contained in paragraphs 1858
and 1879.

January, 10
2011

FERC issued letter order
approving the addition of LSEs
and Controllable Load to the
standard.

Revised

May 9, 2012

Adopted by NERC Board of Trustees;
Modified to add a WECC region
variance

Revised

June 20, 2013

FERC issued order approving VAR-001-3

Revised

November 21,
2013

R5 and associated elements approved
by FERC for retirement as part of the
Paragraph 81 project (Project 2013-02)

Revised

February 6,
2014
August 1, 2014

Adopted by NERC Board of Trustees

Revised

4
4.1
4.1

August 25,
2015
November 13,
2015

FERC issued letter order issued
approving VAR-001-4
Added “or” to Requirement R5, 5.3 to
read: schedules or Reactive Power
FERC Letter Order approved errata to
VAR-001-4.1. Docket RD15-6-000

Errata
Errata

Page 17 of 17

Exhibit B
Proposed Reliability Standard VAR-002-4.1 (Generator Operation for Maintaining
Network Schedules)

Exhibit B-1
Proposed Reliability Standard VAR-002-4.1 Clean

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules

A. Introduction
1.

Title:

Generator Operation for Maintaining Network Voltage Schedules

Number:

Purpose: To ensure generators provide reactive support and voltage control, within generating
Facility capabilities, in order to protect equipment and maintain reliable operation of the
Interconnection.

Applicability:

VAR-002-4.1

4.1. Generator Operator
4.2. Generator Owner
5.

Effective Dates
See Implementation Plan.

B. Requirements and Measures
R1. The Generator Operator shall operate each generator connected to the interconnected
transmission system in the automatic voltage control mode (with its automatic voltage regulator
(AVR) in service and controlling voltage) or in a different control mode as instructed by the
Transmission Operator unless: 1) the generator is exempted by the Transmission Operator, or 2)
the Generator Operator has notified the Transmission Operator of one of the following:
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
• That the generator is being operated in start-up,1 shutdown, 2 or testing mode pursuant to a
Real-time communication or a procedure that was previously provided to the Transmission
Operator; or
• That the generator is not being operated in automatic voltage control mode or in the control
mode that was instructed by the Transmission Operator for a reason other than start-up,
shutdown, or testing.
M1. The Generator Operator shall have evidence to show that it notified its associated Transmission
Operator any time it failed to operate a generator in the automatic voltage control mode or in a
different control mode as specified in Requirement R1. If a generator is being started up or shut
down with the automatic voltage control off, or is being tested, and no notification of the AVR
status is made to the Transmission Operator, the Generator Operator will have evidence that it
notified the Transmission Operator of its procedure for placing the unit into automatic voltage
control mode as required in Requirement R1. Such evidence may include, but is not limited to,
dated evidence of transmittal of the procedure such as an electronic message or a transmittal
letter with the procedure included or attached. If a generator is exempted, the Generator
Operator shall also have evidence that the generator is exempted from being in automatic
voltage control mode (with its AVR in service and controlling voltage).

Start-up is deemed to have ended when the generator is ramped up to its minimum continuously sustainable load and the
generator is prepared for continuous operation.
2
Shutdown is deemed to begin when the generator is ramped down to its minimum continuously sustainable load and the generator
is prepared to go offline.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
R2. Unless exempted by the Transmission Operator, each Generator Operator shall maintain the
generator voltage or Reactive Power schedule 3 (within each generating Facility’s capabilities4)
provided by the Transmission Operator, or otherwise shall meet the conditions of notification
for deviations from the voltage or Reactive Power schedule provided by the Transmission
Operator. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
2.1. When a generator’s AVR is out of service or the generator does not have an AVR, the
Generator Operator shall use an alternative method to control the generator reactive
output to meet the voltage or Reactive Power schedule provided by the Transmission
Operator.
2.2. When instructed to modify voltage, the Generator Operator shall comply or provide an
explanation of why the schedule cannot be met.
2.3. Generator Operators that do not monitor the voltage at the location specified in their
voltage schedule shall have a methodology for converting the scheduled voltage specified
by the Transmission Operator to the voltage point being monitored by the Generator
Operator.
M2.

In order to identify when a generator is deviating from its schedule, the Generator Operator will
monitor voltage based on existing equipment at its Facility. The Generator Operator shall have
evidence to show that the generator maintained the voltage or Reactive Power schedule
provided by the Transmission Operator, or shall have evidence of meeting the conditions of
notification for deviations from the voltage or Reactive Power schedule provided by the
Transmission Operator.
Evidence may include, but is not limited to, operator logs, SCADA data, phone logs, and any other
notifications that would alert the Transmission Operator or otherwise demonstrate that the
Generator Operator complied with the Transmission Operator’s instructions for addressing
deviations from the voltage or Reactive Power schedule.
For Part 2.1, when a generator’s AVR is out of service or the generator does not have an AVR, a
Generator Operator shall have evidence to show an alternative method was used to control the
generator reactive output to meet the voltage or Reactive Power schedule provided by the
Transmission Operator.
For Part 2.2, the Generator Operator shall have evidence that it complied with the Transmission
Operator’s instructions to modify its voltage or provided an explanation to the Transmission
Operator of why the Generator Operator was unable to comply with the instruction. Evidence may
include, but is not limited to, operator logs, SCADA data, and phone logs.
For Part 2.3, for Generator Operators that do not monitor the voltage at the location specified on
the voltage schedule, the Generator Operator shall demonstrate the methodology for converting
the scheduled voltage specified by the Transmission Operator to the voltage point being monitored
by the Generator Operator.

The voltage or Reactive Power schedule is a target value with a tolerance band or a voltage or Reactive Power range communicated
by the Transmission Operator to the Generator Operator.
4
Generating Facility capability may be established by test or other means, and may not be sufficient at times to pull the system
voltage within the schedule tolerance band. Also, when a generator is operating in manual control, Reactive Power capability may
change based on stability considerations.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
R3.
Each Generator Operator shall notify its associated Transmission Operator of a status change on
the AVR, power system stabilizer, or alternative voltage controlling device within 30 minutes of
the change. If the status has been restored within 30 minutes of such change, then the Generator
Operator is not required to notify the Transmission Operator of the status change. [Violation Risk
Factor: Medium] [Time Horizon: Real-time Operations]
M3.

The Generator Operator shall have evidence it notified its associated Transmission Operator
within 30 minutes of any status change identified in Requirement R3. If the status has been
restored within the first 30 minutes, no notification is necessary.

R4.

Each Generator Operator shall notify its associated Transmission Operator within 30 minutes of
becoming aware of a change in reactive capability due to factors other than a status change
described in Requirement R3. If the capability has been restored within 30 minutes of the
Generator Operator becoming aware of such change, then the Generator Operator is not
required to notify the Transmission Operator of the change in reactive capability. [Violation Risk
Factor: Medium] [Time Horizon: Real-time Operations]
•

Reporting of status or capability changes as stated in Requirement R4 is not applicable to
the individual generating units of dispersed power producing resources identified through
Inclusion I4 of the Bulk Electric System definition.

M4.

The Generator Operator shall have evidence it notified its associated Transmission Operator
within 30 minutes of becoming aware of a change in reactive capability in accordance with
Requirement R4. If the capability has been restored within the first 30 minutes, no notification is
necessary.

R5.

The Generator Owner shall provide the following to its associated Transmission Operator and
Transmission Planner within 30 calendar days of a request. [Violation Risk Factor: Lower]
[Time Horizon: Real-time Operations]
5.1. For generator step-up and auxiliary transformers5 with primary voltages equal to or
greater than the generator terminal voltage:

M5.

5.1.1.

Tap settings.

5.1.2.

Available fixed tap ranges.

5.1.3.

Impedance data.

The Generator Owner shall have evidence it provided its associated Transmission Operator and
Transmission Planner with information on its step-up and auxiliary transformers as required in
Requirement R5, Part 5.1.1 through Part 5.1.3 within 30 calendar days.

For dispersed power producing resources identified through Inclusion I4 of the Bulk Electric System definition, this requirement
applies only to those transformers that have at least one winding at a voltage of 100 kV or above.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
R6.
After consultation with the Transmission Operator regarding necessary step-up transformer tap
changes, the Generator Owner shall ensure that transformer tap positions are changed
according to the specifications provided by the Transmission Operator, unless such action would
violate safety, an equipment rating, a regulatory requirement, or a statutory requirement.
[Violation Risk Factor: Lower] [Time Horizon: Real-time Operations]
6.1. If the Generator Owner cannot comply with the Transmission Operator’s specifications, the
Generator Owner shall notify the Transmission Operator and shall provide the technical
justification.
M6.

The Generator Owner shall have evidence that its step-up transformer taps were modified per
the Transmission Operator’s documentation in accordance with Requirement R6. The Generator
Owner shall have evidence that it notified its associated Transmission Operator when it could
not comply with the Transmission Operator’s step-up transformer tap specifications in
accordance with Requirement R6, Part 6.1.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules

C. Compliance
1.

Compliance Monitoring Process:
1.1. Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
refers to NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention:
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances where
the evidence retention period specified below is shorter than the time since the last
audit, the Compliance Enforcement Authority may ask an entity to provide other
evidence to show that it was compliant for the full time period since the last audit.
The Generator Owner shall keep its latest version of documentation on its step-up
and auxiliary transformers. The Generator Operator shall maintain all other evidence
for the current and previous calendar year.
The Compliance Monitor shall retain any audit data for three years.
1.3. Compliance Monitoring and Assessment Processes:
“Compliance Monitoring and Assessment Processes” refers to the identification of
the processes that will be used to evaluate data or information for the purpose of
assessing performance or outcomes with the associated reliability standard.
1.4. Additional Compliance Information:
None.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
Table of Compliance Elements
R#

Time
Horizon

Real-time
Operations

Violation Severity Levels
VRF

Lower VSL

Medium

N/A

Moderate VSL

N/A

High VSL

N/A

Severe VSL
Unless exempted, the
Generator Operator did not
operate each generator
connected to the
interconnected
transmission system in the
automatic voltage control
mode or in a different
control mode as instructed
by the Transmission
Operator, and failed to
provide the required
notifications to
Transmission Operator as
identified in Requirement
R1.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
R#

Time
Horizon

Real-time
Operations

Violation Severity Levels
VRF

Lower VSL

Medium

N/A

Moderate VSL

N/A

High VSL

The Generator
Operator did not
have a conversion
methodology when it
monitors voltage at a
location different
from the schedule
provided by the
Transmission
Operator.

Severe VSL
The Generator Operator did
not maintain the voltage or
Reactive Power schedule as
instructed by the
Transmission Operator and
did not make the necessary
notifications required by
the Transmission Operator.
OR
The Generator Operator
did not have an operating
AVR, and the responsible
entity did not use an
alternative method for
controlling voltage.
OR
The Generator Operator did
not modify voltage when
directed, and the responsible
entity did not provide any
explanation.

Real-time
Operations

Medium

N/A

The Generator Operator
did not make the required
notification within 30
minutes of the status
change.
7

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
R#

Time
Horizon

Real-time
Operations

Violation Severity Levels
VRF

Lower VSL

Medium

Lower

N/A

Moderate VSL

High VSL

N/A

The Generator Owner
failed to provide its
associated
Transmission
Operator and
Transmission Planner
one of the types of
data specified in
Requirement R5 Parts
5.1.1, 5.1.2, and 5.1.3.

Severe VSL
The Generator Operator
did not make the required
notification within 30
minutes of becoming
aware of the capability
change.

The Generator Owner failed
to provide to its associated
Transmission Operator and
Transmission Planner two or
more of the types of data
specified in Requirement R5
Parts 5.1.1, 5.1.2, and 5.1.3.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
R#

Time
Horizon

Violation Severity Levels
VRF

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Generator Owner did
not ensure the tap
changes were made
according the
Transmission Operator’s
specifications.

Real-time
Operations

OR
Lower

N/A

The Generator Owner
failed to perform the tap
changes, and the
Generator Owner did not
provide technical
justification for why it
could not comply with the
Transmission Operator
specifications.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
D. Regional Variances

None.
E. Interpretations

None.
F. Associated Documents

None.
Version History
Version

Date

Action
Added “(R2)” to the end of levels on
non-compliance 2.1.2, 2.2.2, 2.3.2,
and2.4.3.

Change Tracking

5/1/2006

July 5, 2006

12/19/2007

Added Appendix 1 – Interpretation of
R1 and R2 approved by BOT on August
1, 2007

1/16/2007

In Section A.2., Added “a” to end of
standard number. Section F: added
“1.”; and added date.

Errata

1.1a

10/29/2008

BOT adopted errata changes; updated
version number to “1.1a”

Errata

1.1b

3/3/2009

Added Appendix 2 – Interpretation of
VAR-002-1.1a approved by BOT on
February 10, 2009

Revised

4/16/2013

Revised R1 to address an
Interpretation Request. Also added
previously approved VRFs, Time
Horizons and VSLs. Revised R2 to
address consistency issue with VAR001-2, R4.
FERC Order issued approving VAR002-2b.

Revised

5/5/2014

Revised under Project 2013-04 to
address outstanding Order 693
directives.

Revised

5/7/2014

Adopted by NERC Board of Trustees

8/1/2014

Approved by FERC in docket RD14-11000

8/27/2014

Revised under Project 2014-01 to
clarify applicability of Requirements to

Revised

Revised
13

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
BES dispersed power producing
resources.
4

11/13/2014

Adopted by NERC Board of Trustees

5/29/2015

FERC Letter Order in Docket No. RD153-000 approving VAR-002-4

4.1

June 14, 2017

4.1

August 10, 2017

Project 2016-EPR-02 errata
recommendations

Errata

Adopted by the NERC Board of
Trustees

Errata

VAR-002-4.1 Application Guidelines

Guidelines and Technical Basis
Rationale:

This requirement has been maintained due to the importance of running a unit with its automatic
voltage regulator (AVR) in service and in either voltage controlling mode or the mode instructed by
the TOP. However, the requirement has been modified to allow for testing, and the measure has
been updated to include some of the evidence that can be used for compliance purposes.
Rationale for R2:

Requirement R2 details how a Generator Operator (GOP) operates its generator(s) to provide
voltage support and when the GOP is expected to notify the Transmission Operator (TOP). In an
effort to remove prescriptive notification requirements for the entire continent, the VAR-002-3
standard drafting team (SDT) opted to allow each TOP to determine the notification requirements
for each of its respective GOPs based on system requirements. Additionally, a new Part 2.3 has
been added to detail that each GOP may monitor voltage by using its existing facility equipment.
Conversion Methodology: There are many ways to convert the voltage schedule from one voltage
level to another. Some entities may choose to develop voltage regulation curves for their
transformers; others may choose to do a straight ratio conversion; others may choose an entirely
different methodology. All of these methods have technical challenges, but the studies performed
by the TOP, which consider N-1 and credible N-2 contingencies, should compensate for the error
introduced by these methodologies, and the TOP possesses the authority to direct the GOP to
modify its output if its performance is not satisfactory. During a significant system event, such as a
voltage collapse, even a generation unit in automatic voltage control that controls based on the
low-side of the generator step-up transformer should see the event on the low-side of the
generator step-up transformer and respond accordingly.
Voltage Schedule Tolerances: The bandwidth that accompanies the voltage target in a voltage
schedule should reflect the anticipated fluctuation in voltage at the GOP’s Facility during normal
operations and be based on the TOP’s assessment of N‐1 and credible N‐2 system contingencies.
The voltage schedule’s bandwidth should not be confused with the control dead‐band that is
programmed into a GOP’s AVR control system, which should be adjusting the AVR prior to
reaching either end of the voltage schedule’s bandwidth.
Rationale for R3:

This requirement has been modified to limit the notifications required when an AVR goes out of
service and quickly comes back in service. Notifications of this type of status change provide little
to no benefit to reliability. Thirty (30) minutes have been built into the requirement to allow a GOP
time to resolve an issue before having to notify the TOP of a status change. The requirement has
15

VAR-002-4.1 Application Guidelines
also been amended to remove the sub-requirement to provide an estimate for the expected
duration of the status change.
Rationale for R4:

This requirement has been bifurcated from the prior version VAR-002-2b Requirement R3. This
requirement allows GOPs to report reactive capability changes after they are made aware of the
change. The current standard requires notification as soon as the change occurs, but many GOPs
are not aware of a reactive capability change until it has taken place.
Rationale for Exclusion in R4:

VAR-002 addresses control and management of reactive resources and provides voltage control
where it has an impact on the BES. For dispersed power producing resources as identified in
Inclusion I4, Requirement R4 should not apply at the individual generator level due to the unique
characteristics and small scale of individual dispersed power producing resources. In addition,
other standards such as proposed TOP-003 require the Generator Operator to provide Real-time
data as directed by the TOP.
Rationale for R5:

This requirement and corresponding measure have been maintained due to the importance of
having accurate tap settings. If the tap setting is not properly set, then the VARs available from
that unit can be affected. The prior version of VAR-002-2b, Requirement R4.1.4 (the +/- voltage
range with step-change in % for load-tap changing transformers) has been removed. The
percentage information was not needed because the tap settings, ranges and impedance are
required. Those inputs can be used to calculate the step-change percentage if needed.
Rationale for Exclusion in R5:

The Transmission Operator and Transmission Planner only need to review tap settings, available
fixed tap ranges, impedance data and the +/- voltage range with step-change in % for load-tap
changing transformers on main generator step-up unit transformers which connect dispersed
power producing resources identified through Inclusion I4 of the Bulk Electric System definition to
their transmission system. The dispersed power producing resources individual generator
transformers are not intended, designed or installed to improve voltage performance at the point
of interconnection. In addition, the dispersed power producing resources individual generator
transformers have traditionally been excluded from Requirement R4 and R5 of VAR- 002-2b
(similar requirements are R5 and R6 for VAR-002-3), as they are not used to improve voltage
performance at the point of interconnection.
Rationale for R6:

Exhibit B-2
Proposed Reliability Standard VAR-002-4.1 Redline

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules

A. Introduction
1.

Title:

Generator Operation for Maintaining Network Voltage Schedules

Number:

Applicability:

VAR-002-4.1

4.1. Generator Operator
4.2. Generator Owner
5.

Effective Dates
See Implementation Plan.

The voltage or Reactive Power schedule is a target value with a tolerance band or a voltage or Reactive Power range communicated
by the Transmission Operator to the Generator Operator.
4
Generating Facility capability may be established by test or other means, and may not be sufficient at times to pull the system
voltage within the schedule tolerance band. Also, when a generator is operating in manual control, reactive powerReactive Power
capability may change based on stability considerations.

R4.

M4.

R5.

M5.

5.1.1.

Tap settings.

5.1.2.

Available fixed tap ranges.

5.1.3.

Impedance data.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules

C. Compliance
1.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
Table of Compliance Elements
R#

Time
Horizon

Real-time
Operations

Violation Severity Levels
VRF

Lower VSL

Medium

N/A

Moderate VSL

N/A

High VSL

N/A

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
R#

Time
Horizon

Real-time
Operations

Violation Severity Levels
VRF

Lower VSL

Medium

N/A

Moderate VSL

N/A

High VSL

The Generator
Operator did not
have a conversion
methodology when it
monitors voltage at a
location different
from the schedule
provided by the
Transmission
Operator.

Real-time
Operations

Medium

N/A

The Generator Operator
did not make the required
notification within 30
minutes of the status
change.
7

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
R#

Time
Horizon

Real-time
Operations

Violation Severity Levels
VRF

Lower VSL

Medium

Lower

N/A

Moderate VSL

High VSL

N/A

The Generator Owner
failed to provide its
associated
Transmission
Operator and
Transmission Planner
one of the types of
data specified in
Requirement R5 Parts
5.1.1, 5.1.2, and 5.1.3.

Severe VSL
The Generator Operator
did not make the required
notification within 30
minutes of becoming
aware of the capability
change.

The Generator Owner failed
to provide to its associated
Transmission Operator and
Transmission Planner two or
more of the types of data
specified in Requirement R5
Parts 5.1.1, 5.1.2, and 5.1.3.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
R#

Time
Horizon

Violation Severity Levels
VRF

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Generator Owner did
not ensure the tap
changes were made
according the
Transmission Operator’s
specifications.

Real-time
Operations

OR
Lower

N/A

The Generator Owner
failed to perform the tap
changes, and the
Generator Owner did not
provide technical
justification for why it
could not comply with the
Transmission Operator
specifications.

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
D. Regional Variances

None.
E. Interpretations

None.
F. Associated Documents

None.
Version History
Version

Date

Action
Added “(R2)” to the end of levels on
non-compliance 2.1.2, 2.2.2, 2.3.2,
and2.4.3.

Change Tracking

5/1/2006

July 5, 2006

12/19/2007

Added Appendix 1 – Interpretation of
R1 and R2 approved by BOT on August
1, 2007

1/16/2007

In Section A.2., Added “a” to end of
standard number. Section F: added
“1.”; and added date.

Errata

1.1a

10/29/2008

BOT adopted errata changes; updated
version number to “1.1a”

Errata

1.1b

3/3/2009

Added Appendix 2 – Interpretation of
VAR-002-1.1a approved by BOT on
February 10, 2009

Revised

4/16/2013

Revised

5/5/2014

Revised under Project 2013-04 to
address outstanding Order 693
directives.

Revised

5/7/2014

Adopted by NERC Board of Trustees

8/1/2014

Approved by FERC in docket RD14-11000

8/27/2014

Revised under Project 2014-01 to
clarify applicability of Requirements to

Revised

Revised
13

VAR-002-4.1 — Generator Operation for Maintaining Network Voltage Schedules
BES dispersed power producing
resources.
4

11/13/2014

Adopted by NERC Board of Trustees

5/29/2015

FERC Letter Order in Docket No. RD153-000 approving VAR-002-4

4.1

June 14, 2017

Project 1016-EPR-02 errata changes

Errata

4.1

August 10,
2017

Adopted by NERC Board of Trustees

Errata

VAR-002-4.1 Application Guidelines

Guidelines and Technical Basis
Rationale:

VAR-002-4.1 Application Guidelines
also been amended to remove the sub-requirement to provide an estimate for the expected
duration of the status change.
Rationale for R4:

Exhibit C
Proposed WECC Regional Reliability Standard VAR-501-WECC-3.1 (Power System
Stabilizer)

Exhibit C-1
Proposed WECC Regional Reliability Standard VAR-501-WECC-3.1 Clean

VAR-501-WECC-3.1 – Power System Stabilizer

A. Introduction
1. Title:

Power System Stabilizer (PSS)

2. Number: VAR-501-WECC-3.1
3. Purpose: To ensure the Western Interconnection is operated in a coordinated manner
under normal and abnormal conditions by establishing the performance criteria for
WECC power system stabilizers.
4. Applicability:
4.1 Generator Operator
4.2 Generator Owner
5. Facilities: This standard applies to synchronous generators, connected to the Bulk
Electric System, that meet the definition of Commercial Operation.
6. Effective Date: The first day of the first quarter following regulatory approval, except
for Requirement R3.
For units placed in first-time service after regulatory approval, Requirement R3 is
effective the first day of the first quarter following final regulatory approval.
For units placed in service prior to final regulatory approval, Requirement R3 is effective
the first day of the first quarter that is five years after regulatory approval.

B. Requirements and Measures
R1. Each Generator Owner shall provide to its Transmission Operator, the Generator
Owner’s written Operating Procedure or other document(s) describing those known
circumstances during which the Generator Owner’s PSS will not be providing an active
signal to the Automatic Voltage Regulator (AVR), within 180 days of any of the
following events: [Violation Risk Factor: Low] [Time Horizon: Planning Horizon]
• The effective date of this standard;
• The PSS’s Commercial Operation date; or
• Any changes to the PSS operating specifications.
M1. Each Generator Owner will have documented evidence that it provided to its
Transmission Operator, within the time allotted as described in the procedures
required under Requirement R1, written Operating Procedures or other document(s)
describing those known circumstances during which the Generator Owner’s PSS will
not be providing an active signal to the AVR.
For auditing purposes, because Requirement R1 conditions are intended to be
unchanged unless the Transmission Operator is otherwise notified, the Generator
Owner only needs to provide the documentation to the Transmission Operator one
time, or whenever the operating specifications change.

Page 1 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

For auditing purposes, if a PSS is in service but is not providing an active signal to the
AVR as described in Requirement R1, the disabled period does not count against the
Requirement R2 mandate to be in service except as otherwise allowed.
R2. Each Generator Operator shall have its PSS in service while synchronized, except
during any of the following: [Violation Risk Factor: Medium] [Time Horizon: Operating
Assessment]
•

Component failure

•

Testing of a Bulk Electric System Element affecting or affected by the PSS

•

Maintenance

•

As agreed upon by the Generator Operator and the Transmission Operator

A PSS that is out of service for less than 30 minutes does not create a violation
of this Requirement, regardless of cause.
M2. Each Generator Operator will have documentation of each claimed exception
specified in Requirement R2. Documentation may include, but is not limited to:
•

A written explanation covering the bulleted exception that describes the
circumstances of the exception as allowed in Requirement R2.

•

Documented evidence that the Generator Operator and the Transmission
Operator agreed the PSS would not be operating during a specified set of
circumstances, where the exception is claimed under the last bullet of
Requirement R2.

For auditing purposes, the presumption is that the PSS was in service unless otherwise
exempted in Requirement R2. Evidence need only be provided to prove the
circumstances during which the PSS was not in service for periods in excess of 30
minutes.
R3. Each Generator Owner shall tune its PSS to meet the following inter-area mode
criteria, except as specified in Requirement R3, Part 3.5 below: [Violation Risk Factor:
Medium] [Time Horizon: Operating Assessment]
3.1. PSS shall be set to provide the measured, simulated, or calculated compensated
Vt/Vref frequency response of the excitation system and synchronous machine
such that the phase angle will not exceed ± 30 degrees through the frequency
range from 0.2 Hertz to the lesser of 1.0 Hertz or the highest frequency at which
the phase of the Vt/Vref frequency response does not exceed 90 degrees.
3.2. PSS output limits shall be set to provide at least ±5% of the synchronous
machine’s nominal terminal voltage.
3.3. PSS gain shall be set to between 1/3 and 1/2 of maximum practical gain.
3.4. PSS washout time constant shall be no greater than 30 seconds.
Page 2 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

3.5. Units that have an excitation system or PSS that is incapable of meeting the
tuning requirements of Requirement R3 are exempt from Requirement R3 until
the voltage regulator is either replaced or retrofitted such that the PSS becomes
capable of meeting the tuning requirements.
M3. Each Generator Owner will have documented evidence that its PSS was tuned to
meet the specifications of Requirement R3.
If the exception under Requirement R3, Part 3.5, is claimed, the Generator Owner will
have documented evidence describing: 1) the conditions that render the PSS incapable
of meeting the tuning requirements, and 2) the date the voltage regulator was last
replaced or retrofitted.
R4. Each Generator Owner shall install and complete start-up testing of a PSS on its
generator within 180 days of either of the following events: [Violation Risk Factor:
Medium] [Time Horizon: Operational Assessment]
•

The Generator Owner connects a generator to the BES, after achieving
Commercial Operation, and after the Effective Date of this standard.

•

The Generator Owner replaces the voltage regulator on its existing excitation
system, after achieving Commercial Operation for its generator that is
connected to the BES, and after the Effective Date of this standard.

M4. Each Generator Owner will have evidence that it installed and completed start-up
testing of a PSS on its generator within 180 days of either of the conditions described
in Requirement R4, and when those conditions occur after the Effective Date of this
standard.
For auditing purposes of Requirement R4, bullet one only applies to equipment on its
initial (first energization) connection to the BES.
R5. Each Generator Owner shall repair or replace a PSS within 24 months of that PSS
becoming incapable of meeting the tuning specifications stated in Requirement R3.
[Violation Risk Factor: Medium] [Time Horizon: Operational Assessment]
M5. Each Generator Owner will have evidence that it repaired or replaced its PSS within
24 months of that PSS becoming incapable of meeting the tuning specifications of
Requirement R3. Evidence may include, but is not limited to, documentation of the
date the PSS became incapable of meeting the Requirement R3 tuning specifications,
and the date the PSS was returned to service, demonstrating that the span of time
between the two events was less than 24 months.

Page 3 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring and/or
enforcing compliance with mandatory and enforceable Reliability Standards in
their respective jurisdictions.
1.2 Compliance Monitoring and Assessment Processes
•

Compliance Audits

•

Self-Certifications

•

Spot Checking

•

Compliance Investigations

•

Self-Reporting

•

Complaints

1.3 Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to provide
other evidence to show that it was compliant for the full time period since the last
audit.
Each Generator Operator shall keep evidence for all Requirements of the
document for a period of three years plus calendar current.
1.4 Additional Compliance Information
None

D. Regional Differences
None

Page 4 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Table of Compliance Elements
R

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

Planning
Horizon

Low

The Generator Owner
failed to provide its PSS
operating specifications
to the Transmission
Operator as required in
Requirement R1.

Operations
Assessment

Medium

Each Generator
Operator not having
its PSS in service while
synchronized in
accordance with
Requirement R2, for
more than 30 minutes
but less than 60
minutes.

Each Generator
Operator not having its
PSS in service while
synchronized in
accordance with
Requirement R2, for
more than 60 minutes
but less than 120
minutes.

Each Generator
Operator not having
its PSS in service while
synchronized in
accordance with
Requirement R2, for
more than 120
minutes but less than
180 minutes.

Each Generator
Operator not having
its PSS in service while
synchronized in
accordance with
Requirement R2, for
more than 180
minutes.

Operations
Assessment

Medium

The Generator
Owner’s PSS failed to
meet any of the
required
performances in
Requirement R3, two
times or fewer during
the audit period.

The Generator Owner’s
PSS failed to meet any
of the required
performances in
Requirement R3, three
times during the audit
period.

The Generator
Owner’s PSS failed to
meet any of the
required performances
in Requirement R3,
four times during the
audit period.

The Generator
Owner’s PSS failed to
meet any of the
required performances
in Requirement R3,
five times or more
during the audit
period.

Page 5 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Time
Horizon

VRF

Violation Severity Levels

Operational
Assessment

Medium

The Generator Owner
failed to install on its
generator a PSS, as
required in
Requirement R4.

Operational
Assessment

Medium

The Generator Owner
failed to repair or
replace a nonoperational PSS as
required in
Requirement R5.

Lower VSL

Moderate VSL

High VSL

Severe VSL

Page 6 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Version History
Version

Date

April 16, 2008

October 28, 2008

Action
Permanent Replacement
Standard for VAR-STD-002b-1
Adopted by NERC Board of
Trustees

April 21, 2011

FERC Order issued approving
VAR501-WECC-1 (FERC approval
effective June 27, 2011;
Effective Date July 1, 2011)

November 13, 2014

Adopted by NERC Board of
Trustees

March 3, 2015

FERC letter order approved
VAR-501-WECC-2

February 9, 2017

Adopted by NERC Board of
Trustees

April 28, 2017

FERC letter order approved
VAR-501-WECC-3

August 10, 2017

Adopted by the NERC Board of
Trustees

3.1

Change Tracking

Errata

Page 7 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Guideline and Technical Basis
PSS systems are used to minimize real power oscillations by rapidly adjusting the field of the
generator to dampen the low-frequency oscillations.
It is necessary for large numbers of PSS devices to be in operation in the Western
Interconnection to provide the required system damping while still allowing for some of these
units to be out of service whenever necessary.
Mandate to Install a PSS
Nothing in this Regional Reliability Standard (RSS) should be construed to require installation of
a PSS solely because a PSS is not currently installed as of the Effective Date of this RRS. Rather,
installation is only mandated on the occurrence of either of the triggering events described in
Requirement R4, Bullet 1 or Bullet 2, after the Effective Date of the RRS.
It should be noted that a PSS is neither Transmission nor generation.
Requirement R1
Requirement R1 addresses normal operating conditions.
Requirement R1 recognizes that PSS systems have varying states, such as on, off, active, and
non-active. As long as the PSS is operating in accordance with the documentation provided to
the Transmission Operator, this is not considered a status change for purposes of this standard.
This Requirement eliminates the requirement to count hours as required in the previous
version of this standard while also allowing the Generator Owner to create a unit-specific
operating plan.
The intent of Requirement R1 is to provide the Transmission Operator, the PSS operating zone
in which the PSS is “active” providing damping to the power system. Some PSS may be
programmed to become “active” at a specified megawatt loading level and above while others
may be programmed to be “active” in a particular band of megawatt loading levels and are
“non-active” only when passing through the “rough zone” or some other band. A “rough zone”
is a megawatt loading band in which the generator-turbine system could contribute to system
instability.
Requirement R2
This Requirement only applies when the PSS is out of service for a period greater than 30
minutes.
Unlike Requirement R1, Requirement R2 addresses exceptions to normal operation.
The intent of Requirement R2 is to remove the previous requirement to log hours for PSS in
service. In this standard’s previous version, the logged hours were totaled quarterly to meet the
Page 8 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

98% in-service requirement. Instead of documenting the number of hours excluded, this
Requirement simplifies the process by allowing the Generator Operator to communicate to the
Transmission Operator the circumstances that render the PSS unavailable to the Transmission
Operator (such as component failure, maintenance, and testing).
Requirement R3
Nothing in this RSS should be construed to mandate the design criteria for the equipment used
to produce the tuning output of the PSS. Rather, Requirement R3 is intended to address the
design criteria for the tuning output of the PSS.
Unlike the language in Requirement R5 that looks backward to address units that were once
operating but are no longer capable of operating, Requirement R3 looks forward, requiring that
units be tuned to the specified parameters.
The PSS transfer function should compensate the phase characteristics of the generator,
exciter, and power (GEP) system transfer function so the compensated transfer function
((PSS(s) * GEP(s)) has a phase characteristic of ± 30 degrees in the frequency range.
The GEP(s) transfer function is a theoretical transfer function and its phase characteristic
cannot be directly measured during field tests (only via simulation). Thus, the Requirement
recognizes the practical approach of measuring the frequency response between voltage
reference set point and terminal voltage (Et/Vref) and using the phase characteristic of such
frequency response as being the phase characteristic of GEP(s). The phase characteristic of
Et/Vref is a better approximation to the phase characteristic of GEP(s) when the frequency
response Et/Vref is obtained with the generator synchronized to the grid at its minimum stable
power output.
In an effort to allow for reasonable wash-out time constants, the Requirement specifies 0.2 Hz
as the applicable threshold. The 0.2 Hz threshold more closely aligns with the observed
oscillation frequencies.
A properly tuned PSS should provide positive damping to the local mode of oscillation, which
typically has a frequency higher than 1.0 Hz.
This Requirement modifies the requirement associated with the adjustment of the PSS gain.
The standard no longer defines the PSS gain in terms of gain margin but instead requires the
final PSS gain to be between 1/3 (10 dB) and 1/2 (6 dB) of the maximum practical gain that
could be achieved during PSS commissioning. The maximum practical gain might be associated
with the excessive noise or raised higher-frequency oscillations in the closed loop response
(exciter mode) or any other form if there is inadequate closed-loop performance, as
determined during PSS commissioning. It is now part of Measure M3 to show the field test
results that led to the determination of the maximum practical gain.

Page 9 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Requirement R4
Requirement R4 requires a Generator Owner to install a PSS on new applicable units or when
excitation systems are replaced or retrofitted on existing applicable units. This Requirement
applies to new excitation systems and not to existing systems that do not have PSS. The
Requirement also allows a reasonable amount of time for the commissioning of new PSS.
Requirement R5
Unlike the language in Requirement R3 that looks forward to ensure that a unit is tuned,
Requirement R5 looks backward. Specifically, the language in Requirement R5, “becoming
incapable,” indicates the unit was previously capable of meeting the tuning requirements in
Requirement R3, but is no longer capable. Restated, Requirement R5 addresses units that were
previously working but are now no longer working.
The intent of Requirement R5 is to remove the “tiered” approach to PSS repair/replacement
following a failure. A simple, streamlined approach to allow the Generator Owner sufficient
time to repair or replace a broken PSS has been written. Consideration has been given for the
need to procure parts or new equipment, schedule an equipment/unit outage, and install and
test the repaired or replaced PSS. It is recognized that in some instances, it may require
(1) replacement of an AVR, and (2) the existence of a PSS, or both the AVR and the PSS may
need to be replaced to achieve a functioning system.
The 24-month time frame is sufficient to return a functional, operating PSS to service.

Page 10 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

* FOR INFORMATIONAL PURPOSES ONLY *
Enforcement Dates: Standard VAR-501-WECC-3 — Power System Stabilizer
United States
Standard

Requirement

Enforcement Date

VAR-501-WECC-3

TBD

Inactive Date

Page 11 of 11

Exhibit C-2
Proposed WECC Regional Reliability Standard VAR-501-WECC-3.1 Redline

VAR-501-WECC-3.1 – Power System Stabilizer

A. Introduction
1. Title:

Power System Stabilizer (PSS)

Page 1 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Component failure

•

Testing of a Bulk Electric System Element affecting or affected by the PSS

•

Maintenance

•

As agreed upon by the Generator Operator and the Transmission Operator

A written explanation covering the bulleted exception that describes the
circumstances of the exception as allowed in Requirement R2.

•

VAR-501-WECC-3.1 – Power System Stabilizer

The Generator Owner connects a generator to the BES, after achieving
Commercial Operation, and after the Effective Date of this standard.

•

Page 3 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Compliance Audits

•

Self-Certifications

•

Spot Checking

•

Compliance Investigations

•

Self-Reporting

•

Complaints

D. Regional Differences
None

Page 4 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Table of Compliance Elements
R

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

Planning
Horizon

Low

The Generator Owner
failed to provide its PSS
operating specifications
to the Transmission
PlannerOperator as
required in
Requirement R1.

Operations
Assessment

Medium

Each Generator
Operator not having
its PSS in service while
synchronized in
accordance with
Requirement R2, for
more than 30 minutes
but less than 60
minutes.

Each Generator
Operator not having its
PSS in service while
synchronized in
accordance with
Requirement R2, for
more than 60 minutes
but less than 120
minutes.

Each Generator
Operator not having
its PSS in service while
synchronized in
accordance with
Requirement R2, for
more than 120
minutes but less than
180 minutes.

Each Generator
Operator not having
its PSS in service while
synchronized in
accordance with
Requirement R2, for
more than 180
minutes.

Operations
Assessment

Medium

The Generator
Owner’s PSS failed to
meet any of the
required
performances in
Requirement R3, two
times or fewer during
the audit period.

The Generator Owner’s
PSS failed to meet any
of the required
performances in
Requirement R3, three
times during the audit
period.

The Generator
Owner’s PSS failed to
meet any of the
required performances
in Requirement R3,
four times during the
audit period.

The Generator
Owner’s PSS failed to
meet any of the
required performances
in Requirement R3,
five times or more
during the audit
period.

Page 5 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Time
Horizon

VRF

Violation Severity Levels

Operational
Assessment

Medium

The Generator Owner
failed to install on its
generator a PSS, as
required in
Requirement R4.

Operational
Assessment

Medium

The Generator Owner
failed to repair or
replace a nonoperational PSS as
required in
Requirement R5.

Lower VSL

Moderate VSL

High VSL

Severe VSL

Page 6 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Version History
Version

Date

April 16, 2008

October 28, 2008

Action
Permanent Replacement
Standard for VAR-STD-002b-1
Adopted by NERC Board of
Trustees

April 21, 2011

FERC Order issued approving
VAR501-WECC-1 (FERC approval
effective June 27, 2011;
Effective Date July 1, 2011)

November 13, 2014

Adopted by NERC Board of
Trustees

March 3, 2015

FERC letter order approved
VAR-501-WECC-2

TBDFebruary 9,
2017

TBDAdopted by NERC Board of
Trustees

April 28, 2017

FERC letter order approved
VAR-501-WECC-3

August 10, 2017

Adopted by the NERC Board of
Trustees

3.1

Change Tracking

Errata

Page 7 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Guideline and Technical Basis
PSS systems are used to minimize real power oscillations by rapidly adjusting the field of the
generator to dampen the low-frequency oscillations.
It is necessary for large numbers of PSS devices to be in operation in the Western
Interconnection to provide the required system damping while still allowing for some of these
units to be out of service whenever necessary.
Mandate to Install a PSS
Nothing in this Regional Reliability Standard (RSS) should be construed to require installation of
a PSS solely because a PSS is not currently installed as of the Effective Date of this RRS. Rather,
installation is only mandated on the occurrence of either of the triggering events described in
Requirement R4, Bullet 1 or Bullet 2, after the Effective Date of the RRS.
It should be noted that a PSS is neither Transmission nor generation.
Requirement R1
Requirement R1 addresses normal operating conditions.
Requirement R1 recognizes that PSS systems have varying states, such as on, off, active, and
non-active. As long as the PSS is operating in accordance with the documentation provided to
the Transmission PlannerOperator, this is not considered a status change for purposes of this
standard.
This Requirement eliminates the requirement to count hours as required in the previous
version of this standard while also allowing the Generator Owner to create a unit-specific
operating plan.
The intent of Requirement R1 is to provide the Transmission PlannerOperator, the PSS
operating zone in which the PSS is “active” providing damping to the power system. Some PSS
may be programmed to become “active” at a specified megawatt loading level and above while
others may be programmed to be “active” in a particular band of megawatt loading levels and
are “non-active” only when passing through the “rough zone” or some other band. A “rough
zone” is a megawatt loading band in which the generator-turbine system could contribute to
system instability.
Requirement R2
This Requirement only applies when the PSS is out of service for a period greater than 30
minutes.
Unlike Requirement R1, Requirement R2 addresses exceptions to normal operation.

Page 8 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

The intent of Requirement R2 is to remove the previous requirement to log hours for PSS in
service. In this standard’s previous version, the logged hours were totaled quarterly to meet the
98% in-service requirement. Instead of documenting the number of hours excluded, this
Requirement simplifies the process by allowing the Generator Operator to communicate to the
Transmission Operator the circumstances that render the PSS unavailable to the Transmission
Operator (such as component failure, maintenance, and testing).
Requirement R3
Nothing in this RSS should be construed to mandate the design criteria for the equipment used
to produce the tuning output of the PSS. Rather, Requirement R3 is intended to address the
design criteria for the tuning output of the PSS.
Unlike the language in Requirement R5 that looks backward to address units that were once
operating but are no longer capable of operating, Requirement R3 looks forward, requiring that
units be tuned to the specified parameters.
The PSS transfer function should compensate the phase characteristics of the generator,
exciter, and power (GEP) system transfer function so the compensated transfer function
((PSS(s) * GEP(s)) has a phase characteristic of ± 30 degrees in the frequency range.
The GEP(s) transfer function is a theoretical transfer function and its phase characteristic
cannot be directly measured during field tests (only via simulation). Thus, the Requirement
recognizes the practical approach of measuring the frequency response between voltage
reference set point and terminal voltage (Et/Vref) and using the phase characteristic of such
frequency response as being the phase characteristic of GEP(s). The phase characteristic of
Et/Vref is a better approximation to the phase characteristic of GEP(s) when the frequency
response Et/Vref is obtained with the generator synchronized to the grid at its minimum stable
power output.
In an effort to allow for reasonable wash-out time constants, the Requirement specifies 0.2 Hz
as the applicable threshold. The 0.2 Hz threshold more closely aligns with the observed
oscillation frequencies.
A properly tuned PSS should provide positive damping to the local mode of oscillation, which
typically has a frequency higher than 1.0 Hz.
This Requirement modifies the requirement associated with the adjustment of the PSS gain.
The standard no longer defines the PSS gain in terms of gain margin but instead requires the
final PSS gain to be between 1/3 (10 dB) and 1/2 (6 dB) of the maximum practical gain that
could be achieved during PSS commissioning. The maximum practical gain might be associated
with the excessive noise or raised higher-frequency oscillations in the closed loop response
(exciter mode) or any other form if there is inadequate closed-loop performance, as
determined during PSS commissioning. It is now part of Measure M3 to show the field test
results that led to the determination of the maximum practical gain.

Page 9 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

Page 10 of 11

VAR-501-WECC-3.1 – Power System Stabilizer

* FOR INFORMATIONAL PURPOSES ONLY *
Enforcement Dates: Standard VAR-501-WECC-3 — Power System Stabilizer
United States
Standard

Requirement

Enforcement Date

VAR-501-WECC-3

TBD

Inactive Date

Page 11 of 11

File Type	application/pdf
File Title	Petition for Approval of VAR and WECC VAR Errata
Author	NERC Legal (ST)
File Modified	2017-10-11
File Created	2017-08-18