NERC Petition

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 RELIABILITY STANDARDS DEVELOPED UNDER THE
STANDARDS ALIGNMENT WITH REGISTRATION PROJECT

Lauren A. Perotti
Senior 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
lauren.perotti@nerc.net
Counsel for the North American Electric
Reliability Corporation

February 21, 2020

TABLE OF CONTENTS
NOTICES AND COMMUNICATIONS ............................................................................. 4
BACKGROUND .................................................................................................................. 4
Regulatory Framework .................................................................................................... 4
NERC Reliability Standards Development Procedure .................................................... 5
NERC’s Risk-Based Registration Initiative and Project 2017-07 Standards Alignment
with Registration .......................................................................................................... 6
JUSTIFCATION FOR APPROVAL ................................................................................... 7
Proposed Reliability Standard FAC-002-3 – Facility Interconnection Studies ............... 8
Proposed Reliability Standard IRO-010-3 – Reliability Coordinator Data Specification
and Collection .............................................................................................................. 9
Proposed Reliability Standard MOD-031-3 – Demand and Energy Data ..................... 10
Proposed Reliability Standard MOD-033-2 – Steady-State and Dynamic System Model
Validation .................................................................................................................. 11
Proposed Reliability Standard NUC-001-4 – Nuclear Plant Interface Coordination .... 11
Proposed Reliability Standard PRC-006-4 – Automatic Underfrequency Load
Shedding .................................................................................................................... 13
Proposed Reliability Standard TOP-003-4 – Operational Reliability Data ................... 14
Enforceability of the Proposed Reliability Standards .................................................... 15
EFFECTIVE DATE ........................................................................................................... 15
CONCLUSION .................................................................................................................. 16

i

Exhibit A

Exhibit B
Exhibit C
Exhibit D

Exhibit E
Exhibit F

The proposed Reliability Standards
Exhibit A-1: Proposed Reliability Standard FAC-002-3
Clean
Redline to Last Approved (FAC-002-2)
Exhibit A-2: Proposed Reliability Standard IRO-010-3
Clean
Redline to Last Approved (IRO-010-2)
Exhibit A-3: Proposed Reliability Standard MOD-031-3
Clean
Redline to Last Approved (MOD-031-2)
Exhibit A-4: Proposed Reliability Standard MOD-033-2
Clean
Redline to Last Approved (MOD-033-1)
Exhibit A-5: Proposed Reliability Standard NUC-001-4
Clean
Redline to Last Approved (NUC-001-3)
Exhibit A-6: Proposed Reliability Standard PRC-006-4
Clean
Redline to Last Approved (PRC-006-3)
Exhibit A-7: Proposed Reliability Standard TOP-003-4
Clean
Redline to Last Approved (TOP-003-3)
Implementation Plan
Order No. 672 Criteria
Analysis of Violation Risk Factors and Violation Severity Levels
Exhibit D-1: Proposed Reliability Standard FAC-002-3
Exhibit D-2: Proposed Reliability Standard IRO-010-3
Exhibit D-3: Proposed Reliability Standard MOD-031-3
Exhibit D-4: Proposed Reliability Standard MOD-033-2
Exhibit D-5: Proposed Reliability Standard NUC-001-4
Exhibit D-6: Proposed Reliability Standard PRC-006-4
Exhibit D-7: Proposed Reliability Standard TOP-003-4
Summary of Development and Complete Record of Development
Standard Drafting Team Roster, Project 2017-07 Standards Alignment with
Registration

ii

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 RELIABILITY STANDARDS DEVELOPED UNDER THE
STANDARDS ALIGNMENT WITH REGISTRATION PROJECT
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
seven proposed Reliability Standards:
•

Reliability Standard FAC-002-3 – Facility Interconnection Studies

•

Reliability Standard IRO-010-3 – Reliability Coordinator Data Specification and
Collection

•

Reliability Standard MOD-031-3 – Demand and Energy Data

•

Reliability Standard MOD-033-2 – Steady-State and Dynamic System Model
Validation

•

Reliability Standard NUC-001-4 – Nuclear Plant Interface Coordination

•

Reliability Standard PRC-006-4 – Automatic Underfrequency Load Shedding

•

Reliability Standard TOP-003-4 – Operational Reliability Data

1

16 U.S.C. § 824o (2018).
18 C.F.R. § 39.5 (2019).
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, order on reh’g and compliance,
117 FERC ¶ 61,126 (2006), order on compliance, 118 FERC ¶ 61,030, order on compliance, 118 FERC ¶ 61,190,
order on reh’g, 119 FERC ¶ 61,046 (2007), aff’d sub nom. Alcoa Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009).
2

1

The proposed Reliability Standards revise the currently effective versions to align the
standards with registration changes approved by the Commission in 2015. 4 In the proposed
Reliability Standards, references to entities that are no longer registered by NERC are removed.
Proposed Reliability Standard PRC-006-3 adds the Underfrequency Load Shedding (“UFLS”)Only Distribution Provider as an applicable entity. In addition, revisions are proposed to ensure
consistent use of the term Planning Coordinator across the body of NERC Reliability Standards.
No substantive revisions are made to the underlying requirements.
NERC requests that the Commission approve the proposed Reliability Standards, as shown
in Exhibit A, as just, reasonable, not unduly discriminatory or preferential, and in the public
interest. NERC requests that the Commission also approve: (i) the implementation plan (Exhibit
B); (ii) the associated Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”)
(Exhibit D), which are generally unchanged from the currently effective versions of those
standards; and (iii) the retirement of the currently effective versions of the proposed Reliability
Standards.
As required by Section 39.5(a) 5 of the Commission’s regulations, this petition presents the
technical basis and purpose of the proposed Reliability Standards, a demonstration that the
proposed Reliability Standards continue to meet the criteria identified by the Commission in Order
No. 672 6 (Exhibit C), and a summary of the standard development history (Exhibit E). The NERC
Board of Trustees adopted the proposed Reliability Standards on February 6, 2020.

4

See infra Section II.C.
18 C.F.R. § 39.5(a).
6
The Commission specified in Order No. 672 certain general factors it would consider when assessing whether
a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric Reliability
Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards,
Order No. 672, 114 FERC ¶ 61,104 at PP 321-37 (2006 ) [hereinafter Order No. 672], order on reh’g, Order No. 672A, 114 FERC ¶ 61,328 (2006).
5

2

This petition is organized as follows: Section I of the petition provides the individuals to
whom notices and communications related to the filing should be provided. Section II provides
background on the regulatory structure governing the Reliability Standards approval process. This
section also provides information on the registration changes, developed under NERC’s RiskBased Registration Initiative and approved by the Commission in 2015, which led to the
development of the proposed standards. Section III of the petition provides the procedural history
for each of the proposed Reliability Standards, a summary of the proposed revisions, and the
justification supporting the proposals. Section IV of the petition provides a summary of the
proposed implementation plan.

3

NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the following: 7
Lauren A. Perotti*
Senior 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
lauren.perotti@nerc.net
marisa.hecht@nerc.net

Howard Gugel*
Vice President and Director of Engineering and Standards
North American Electric Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
howard.gugel@nerc.net

BACKGROUND
Regulatory Framework
By enacting the Energy Policy Act of 2005, 8 Congress entrusted the Commission with the
duties of approving and enforcing rules to ensure the reliability of the Bulk-Power System
(“BPS”), and with the duties of certifying an ERO that would be charged with developing and
enforcing mandatory Reliability Standards, subject to Commission approval. Section 215(b)(1) 9
of the FPA states that all users, owners, and operators of the BPS in the United States will be
subject to Commission-approved Reliability Standards. Section 215(d)(5) 10 of the FPA authorizes
the Commission to order the ERO to submit a new or modified Reliability Standard. Section
39.5(a) 11 of the Commission’s regulations requires the ERO to file with the Commission for its

7

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, to allow the inclusion of more
than two persons on the service list in this proceeding.
8
16 U.S.C. § 824o.
9
Id. § 824o(b)(1).
10
Id. § 824o(d)(5).
11
18 C.F.R. § 39.5(a).

4

approval each new Reliability Standard that the ERO proposes should become mandatory and
enforceable in the United States, and each modification to a Reliability Standard that the ERO
proposes should be made effective.
The Commission is vested with the regulatory responsibility to approve Reliability
Standards that protect the reliability of the BPS and to ensure that Reliability Standards are just,
reasonable, not unduly discriminatory or preferential, and in the public interest. Pursuant to
Section 215(d)(2) of the FPA 12 and Section 39.5(c) 13 of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the content
of a Reliability Standard.
NERC Reliability Standards Development Procedure
The proposed Reliability Standards discussed in this petition were developed in an open
and fair manner and in accordance with the Commission-approved Reliability Standard
development process. NERC develops Reliability Standards in accordance with Section 300
(Reliability Standards Development) of its Rules of Procedure and the NERC Standard Processes
Manual. 14
In its order certifying NERC as the Commission’s ERO, the Commission found that
NERC’s rules provide for reasonable notice and opportunity for public comment, due process,
openness, and a balance of interests in developing Reliability Standards, 15 and thus satisfy several
of the Commission’s criteria for approving Reliability Standards. 16 The development process is

12

16 U.S.C. § 824o(d)(2).
18 C.F.R. § 39.5(c)(1).
14
The NERC Rules of Procedure, including Appendix 3A, NERC Standard Processes Manual, is available at
https://www.nerc.com/AboutNERC/Pages/Rules-of-Procedure.aspx.
15
N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 at P 250.
16
Order No. 672, supra note 6, at PP 268, 270.
13

5

open to any person or entity with a legitimate interest in the reliability of the BPS. NERC considers
the comments of all stakeholders. Stakeholders must approve, and the NERC Board of Trustees
must adopt, a new or revised Reliability Standard before NERC submits the Reliability Standard
to the Commission for approval. Similarly, stakeholders and the NERC Board of Trustees must
approve the retirement of a Reliability Standard before the retirement is submitted to the
Commission for approval.
NERC’s Risk-Based Registration Initiative and Project 2017-07 Standards
Alignment with Registration
On March 19, 2015, the Commission approved a series of proposed Rules of Procedure
revisions to implement the NERC Risk-Based Registration Initiative. 17 The Commission approved
the removal of two functional categories, Purchasing-Selling Entity and Interchange Authority,
from the NERC Compliance Registry due to the commercial nature of these categories posing little
or no risk to the reliability of the Bulk-Power System. 18 The Commission also approved the
creation of a new registration category, UFLS-only Distribution Provider, and the risk-based
application of sub-set lists of Reliability Standards to the UFLS-only Distribution Provider.19
Subsequently, following a compliance filing, the Commission approved the removal of the LoadServing Entity from the NERC registry criteria. 20
Several projects have either already addressed, or will address, Reliability Standards
impacted by the registration changes approved by the Commission in 2015. NERC initiated Project
2017-07 to address any remaining edits to the Reliability Standards that were needed to align the
existing Reliability Standards with the registration changes.
17
N. Am. Elec. Reliability Corp., Order on Electric Reliability Organization Risk Based Registration Initiative
and Requiring Compliance Filing, 150 FERC ¶ 61,213 (2015).
18
Id. at PP 25-26.
19
Id. at PP 52-53.
20
N. Am. Elec. Reliability Corp., Order on Compliance Filing, 153 FERC ¶ 61,024 at P 24 (2015).

6

The proposed Reliability Standards were posted for formal comment and ballot from
October 29, 2019 to December 12, 2019 and for final ballot from January 14, 2020 to January 23,
2020. Having achieved the requisite quorum and ballot body approval percentages, the NERC
Board of Trustees adopted the proposed Reliability Standards on February 6, 2020. A summary of
the development history and the complete record of development is attached to this petition as
Exhibit E.
JUSTIFCATION FOR APPROVAL
In this petition, NERC proposes for Commission approval seven revised Reliability
Standards:
•

Reliability Standard FAC-002-3 – Facility Interconnection Studies

•

Reliability Standard IRO-010-3 – Reliability Coordinator Data Specification and
Collection

•

Reliability Standard MOD-031-3 – Demand and Energy Data

•

Reliability Standard MOD-033-2 – Steady-State and Dynamic System Model
Validation

•

Reliability Standard NUC-001-4 – Nuclear Plant Interface Coordination

•

Reliability Standard PRC-006-4 – Automatic Underfrequency Load Shedding

•

Reliability Standard TOP-003-4 – Operational Reliability Data

As discussed more fully below, the revisions in the proposed Reliability Standards will
align these standards with the previously-approved changes to the NERC registration criteria by
removing reference to entities that are no longer registered with NERC. In proposed Reliability
Standard PRC-006-4, NERC adds the UFLS-only Distribution Provider as an applicable entity. In
two instances, NERC has proposed changes that will promote consistent use of the term Planning
Coordinator across the Reliability Standards. Where appropriate, NERC has made corresponding
revisions to the VRFs, VSLs, measures, and the supplemental material included as information.
No substantive changes are proposed to any Reliability Standard requirement.

7

The proposed revisions will promote alignment and consistency across NERC Reliability
Standards and the NERC registration criteria and will reduce the potential for confusion regarding
which entities are responsible for compliance with the standards. For these reasons, the proposed
Reliability Standards should be approved as just, reasonable, not unduly discriminatory or
preferential, and in the public interest. The following sections provide a brief overview of the
procedural history for each standard and a summary of the changes and supporting justification.
Proposed Reliability Standard FAC-002-3 – Facility Interconnection Studies
Procedural History
The Commission approved the first version of the FAC-002 Reliability Standard, FAC002-0, in Order No. 693. 21 Reliability Standard FAC-002-1 was approved by the Commission in
2011. 22 Currently effective Reliability Standard FAC-002-2 was approved by the Commission on
November 6, 2014. 23
Summary of Proposed Revisions
The purpose of proposed Reliability Standard FAC-002-3, which remains unchanged from
the currently effective version, is “to study the impact of interconnecting new or materially
modified Facilities on the Bulk Electric System.” The currently effective standard is applicable to
the Planning Coordinator, Transmission Planner, Transmission Owner, Distribution Provider,
Generator Owner (including Applicable Generator Owner as defined in the standard), and the
Load-Serving Entity. As the Load-Serving Entity is no longer a NERC registration category,
NERC proposes to remove this entity from the applicability section of proposed Reliability
Standard FAC-002-3 and remove reference to this entity in Requirement R3. This revision aligns

21

Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 118 FERC ¶ 61,218 at P 693
(2007) [hereinafter Order No. 693].
22
N. Am. Elec. Reliability Corp., 134 FERC ¶ 61,015 (2011).
23
N. Am. Elec. Reliability Corp., Docket No. RD14-12-000 (Nov. 6, 2014) (delegated letter order).

8

the FAC-002 standard with the NERC registration criteria and reduces the potential for confusion
regarding which entities must comply with the standard.
Proposed Reliability Standard IRO-010-3 – Reliability Coordinator Data
Specification and Collection
Procedural History
The Commission approved the first version of the IRO-010 Reliability Standard submitted
for Commission approval, Reliability Standard IRO-010-1a, in Order No. 748, issued in 2011.24
The Commission approved currently effective Reliability Standard IRO-010-2 in Order No. 817,
issued in 2015. 25
Summary of Proposed Revisions
The purpose of proposed Reliability Standard IRO-010-3, which remains unchanged from
the currently effective version, is “to prevent instability, uncontrolled separation, or Cascading
outages that adversely impact reliability, by ensuring the Reliability Coordinator has the data it
needs to monitor and assess the operation of its Reliability Coordinator Area.” The currently
effective standard is applicable to the Reliability Coordinator, Balancing Authority, Generator
Owner, Generator Operator, Load-Serving Entity, Transmission Operator, Transmission Owner,
and Distribution Provider. As the Load-Serving Entity is no longer a NERC registration category,
NERC proposes to remove this entity from the applicability section of proposed Reliability
Standard IRO-010-3 and remove reference to this entity in Requirement R3. As with other
standards in which this revision is made, this revision will align the standard with the NERC

24

Mandatory Reliability Standards for Interconnection Reliability Operating Limits, Order No. 748, 134 FERC
¶ 61,213 at P 21 (2011) [hereinafter Order No. 748].
25
Transmission Operations Reliability Standards and Interconnection Reliability Operations and Coordination
Reliability Standards, 153 FERC ¶ 61,178 at P 1 (2015) [hereinafter Order No. 817].

9

registration criteria and reduce the potential for confusion regarding which entities must comply
with the standard.
Proposed Reliability Standard MOD-031-3 – Demand and Energy Data
Procedural History
The Commission approved the first version of the MOD-031 Reliability Standard, MOD031-1, in Order No. 804, issued in 2015. 26 The Commission approved currently effective
Reliability Standard MOD-031-2 in 2016. 27
Summary of Proposed Revisions
The purpose of proposed Reliability Standard MOD-031-3, which remains unchanged
from the currently effective version, is “to provide authority for applicable entities to collect
Demand, energy and related data to support reliability studies and assessments and to enumerate
the responsibilities and obligations of requestors and respondents of that data.” The currently
effective standard is applicable to the Planning Authority/Planning Coordinator, Transmission
Planner, Balancing Authority, Resource Planner, Load-Serving Entity, and Distribution Provider.
As the Load-Serving Entity is no longer a NERC registration category, NERC proposes to
remove this entity from the applicability section of proposed Reliability Standard MOD-031-3 and
remove reference to this entity in Requirement R1 Part 1.1, where it is listed as an “Applicable
Entity” for purposes of Requirements R2 and R4. Additionally, NERC proposes to strike the term
“Planning Authority” from the applicability section of the standard and the explanatory text that
follows. The preferred terminology for the responsible entity that coordinates and integrates
transmission Facilities and service plans, resource plans, and Protection Systems is Planning

26

Demand and Energy Data Reliability Standard, Order No. 804, 150 FERC ¶ 61,109 (2015). Reliability
Standard MOD-031-1 was developed to replace a suite of MOD Reliability Standards referred to as the “MOD C”
standards originally approved by the Commission in Order No. 693.
27
N. Am. Elec. Reliability Corp., Docket No. RD16-1-000 (Feb. 18, 2016) (delegated letter order).

10

Coordinator. The proposed changes are intended to promote alignment with the registration
criteria, ensure consistency in terminology, and reduce the potential for confusion regarding which
entities are responsible for compliance with the standard.
Proposed Reliability Standard MOD-033-2 – Steady-State and Dynamic
System Model Validation
Procedural History
The Commission approved currently effective Reliability Standard MOD-033-1 in 2014.28
Summary of Proposed Revisions
The purpose of proposed Reliability Standard MOD-033-2, which remains unchanged
from the currently effective version, is “to establish consistent validation requirements to facilitate
the collection of accurate data and building of planning models to analyze the reliability of the
interconnected transmission system.” The currently effective standard is applicable to the Planning
Authority/Planning Coordinator, Reliability Coordinator, and Transmission Operator. In proposed
Reliability Standard MOD-033-2, NERC proposes to strike the term “Planning Authority” from
the applicability section of the standard and the explanatory text that follows. As noted in the
preceding section, the proposed change is intended to promote consistent use of “Planning
Coordinator” throughout the Reliability Standards.
Proposed Reliability Standard NUC-001-4 – Nuclear Plant Interface
Coordination
Procedural History
The Commission approved the first version of the NUC-001 Reliability Standard, NUC-

28

N. Am. Elec. Reliability Corp., Docket No. RD14-5-000 (May 1, 2014) (delegated letter order). Reliability
Standard MOD-033-1 was developed to replace a suite of MOD Reliability Standards referred to as the “MOD B”
standards, two of which were approved by the Commission in Order No. 693 and four of which were later withdrawn
by NERC.

11

001-1, in Order No. 716 issued in 2008. 29 Reliability Standard NUC-001-2 was approved by the
Commission in 2010. 30 The Commission approved the retirement of NUC-001-2 Requirements
R9.1, R9.1.1, R9.1.2, R9.1.3, and R9.1.4 in Order No. 788, issued in 2013. 31 The Commission
approved currently effective Reliability Standard NUC-001-3 in 2014. 32
Summary of Proposed Revisions
The purpose of proposed Reliability Standard NUC-001-4, which remains unchanged from
the currently effective version, is as follows: “This standard requires coordination between Nuclear
Plant Generator Operators and Transmission Entities for the purpose of ensuring nuclear plant safe
operation and shutdown.” The standard is applicable to Nuclear Plant Generator Operators and
Transmission Entities, which may include Transmission Operators, Transmission Owners,
Transmission Planners, Transmission Service Providers, Balancing Authorities, Reliability
Coordinators, Planning Coordinators, Distribution Providers, Load-Serving Entities, Generator
Owners, and Generator Operators. As the Load-Serving Entity is no longer a NERC registration
category, NERC proposes to remove this entity from the list of applicable Transmission Entities
in the applicability section of proposed Reliability Standard NUC-001-4. As with other standards
in which this revision is made, this revision will align the standard with the NERC registration

29

Mandatory Reliability Standard for Nuclear Plant Interface Coordination, Order No. 716, 125 FERC ¶
61,065 (2008).
30
N. Am. Elec. Reliability Corp., 130 FERC ¶ 61,051 (2010).
31
Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 145 FERC ¶
61,147 (2013).
32
N. Am. Elec. Reliability Corp., Docket No. RD14-13-000 (Nov. 4, 2014) (delegated letter order).

12

criteria and reduce the potential for confusion regarding which entities must comply with the
standard.
Proposed Reliability Standard PRC-006-4 – Automatic Underfrequency Load
Shedding
Procedural History
The Commission approved Reliability Standard PRC-006-1 in Order No. 763, issued in
2012. 33 Reliability Standard PRC-006-2 was approved by the Commission in 2015. 34 Currently
effective Reliability Standard PRC-006-3 added a regional Variance for the Quebec
Interconnection; none of the requirements applicable in the United States were changed. The
standard was provided to the Commission for information on September 5, 2017. 35
Summary of Proposed Revisions
The purpose of proposed Reliability Standard PRC-006-4, which remains unchanged from
the currently effective version, is “to establish design and documentation requirements for
automatic underfrequency load shedding (UFLS) programs to arrest declining frequency, assist
recovery of frequency following underfrequency events and provide last resort system preservation
measures.” The currently effective standard is applicable to Planning Coordinators, “UFLS
entities” (which may include Transmission Owners and Distribution Providers that own, operate,
or control UFLS equipment), and Transmission Owners that own certain Elements. In proposed
Reliability Standard PRC-006-4, NERC proposes to add the UFLS-Only Distribution Provider as
an applicable UFLS entity, consistent with the language in Section III(b) of Appendix 5B of the

33

Automatic Underfrequency Load Shedding and Load Shedding Plans Reliability Standards, Order No. 763,
139 FERC ¶ 61,098 (2012). The Commission neither approved nor remanded proposed Reliability Standard PRC006-0 in Order No. 693. See Order No. 693, supra note 20, at P 1479.
34
N. Am. Elec. Reliability Corp., Docket No. RD15-2-000 (Mar. 4, 2015) (delegated letter order).
35
Informational Filing regarding Reliability Standard PRC-006-3 (Automatic Underfrequency Load
Shedding), Docket No. RD15-2-000 (Sep. 5, 2017).

13

NERC Rules of Procedure (Statement of Compliance Registry Criteria) that the Reliability
Standards applicable to UFLS-Only Distribution Providers includes prior effective versions of the
PRC-006 standard.
Proposed Reliability Standard TOP-003-4 – Operational Reliability Data
Procedural History
The Commission approved the first version of the TOP-003 Reliability Standard, TOP003-0, in Order No. 693 issued in 2007. 36 Reliability Standard TOP-003-1 was approved in Order
No. 748, issued in 2011. 37 Currently effective Reliability Standard TOP-003-3 was approved by
the Commission in Order No. 817, issued in 2015. 38
Summary of Proposed Revisions
The purpose of proposed Reliability Standard TOP-003-4, which remains unchanged from
the currently effective version, is “to ensure that the Transmission Operator and Balancing
Authority have data needed to fulfill their operational and planning responsibilities.” The currently
effective standard is applicable to the Transmission Operator, Balancing Authority, Generator
Owner, Generator Operator, Load-Serving Entity, Transmission Owner, and Distribution Provider.
As the Load-Serving Entity is no longer a NERC registration category, NERC proposes to remove
this entity from the applicability section of proposed Reliability Standard TOP-003-4 and remove
reference to this entity in Requirement R5. As with other standards in which this revision is made,

36

Order No. 693, supra note 20, at P 1619. Reliability Standard TOP-003-3 replaced proposed version TOP003-2, which was filed and later withdrawn by NERC.
37
Order No. 748, supra note 23, at P 21.
38
Order No. 817, supra note 24, at P 1.

14

this revision will align the standard with the NERC registration criteria and reduce the potential
for confusion regarding which entities must comply with the standard.
Enforceability of the Proposed Reliability Standards
The proposed Reliability Standards contain Violation Risk Factors (“VRFs”) and Violation
Severity Levels (“VSLs”) for each of the requirements. The VRFs and VSLs provide guidance on
the way that NERC will enforce the requirements of the proposed Reliability Standards. The VRFs
and VSLs are substantively unchanged from currently effective versions of the Reliability
Standards, reflecting only those revisions necessary to effectuate the proposed alignment revisions.
As such, they continue to comport with NERC and Commission guidelines related to their
assignment.
In addition, the proposed Reliability Standards also include measures that support the
requirements by clearly identifying what is required and how the requirement will be enforced.
The measures help ensure that the requirements will be enforced in a clear, consistent, and nonpreferential manner and without prejudice to any party. The measures are substantively unchanged
from currently enforceable versions of the Reliability Standards, reflecting only those revisions
necessary to effectuate the proposed alignment revisions.
EFFECTIVE DATE
NERC respectfully requests that the Commission approve the proposed implementation
plan attached to this petition as Exhibit B. The proposed implementation plan provides that the
proposed Reliability Standards would become effective on the first day of the first calendar quarter
that is three months after applicable regulatory approval. The currently effective versions of the
standards would be retired immediately prior to the effective date of the revised Reliability
Standards. This implementation timeline reflects consideration that entities may need time to

15

update their internal systems and documentation to reflect the new Reliability Standard version
numbers.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve:
•

proposed Reliability Standards FAC-002-3, IRO-010-3, MOD-031-3, MOD-033-2,
NUC-001-4, PRC-006-4, and TOP-003-4, and the associated elements included in
Exhibit A;

•

the implementation plan included in Exhibit B; and

•

the retirement of Reliability Standards FAC-002-2, IRO-010-2, MOD-031-2, MOD033-1, NUC-001-3, PRC-006-3, and TOP-003-3.

Respectfully submitted,
/s/ Lauren A. Perotti
Lauren A. Perotti
Senior 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
lauren.perotti@nerc.net
Counsel for the North American Electric
Reliability Corporation
February 21, 2020

16

Exhibit A
The Proposed Reliability Standards Developed
Under Project 2017-17 Standards Alignment with Registration

RELIABILITY | RESILIENCE | SECURITY

Exhibit A-1
Proposed Reliability Standard FAC-002-3
Clean

RELIABILITY | RESILIENCE | SECURITY

FAC-002-3 — Facility Interconnection Studies

A. Introduction
1.

Title:

Facility Interconnection Studies

2.

Number:

FAC-002-3

3.

Purpose: To study the impact of interconnecting new or materially modified
Facilities on the Bulk Electric System.

4.

Applicability:
4.1. Functional Entities:
4.1.1 Planning Coordinator
4.1.2 Transmission Planner
4.1.3 Transmission Owner
4.1.4 Distribution Provider
4.1.5 Generator Owner
4.1.6 Applicable Generator Owner

5.

4.1.6.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
Effective Date: See Implementation Plan

B. Requirements and Measures
R1.

Each Transmission Planner and each Planning Coordinator shall study the reliability
impact of: (i) interconnecting new generation, transmission, or electricity end-user
Facilities and (ii) materially modifying existing interconnections of generation,
transmission, or electricity end-user Facilities. The following shall be studied:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
1.1. The reliability impact of the new interconnection, or materially modified existing
interconnection, on affected system(s);
1.2. Adherence to applicable NERC Reliability Standards; regional and Transmission
Owner planning criteria; and Facility interconnection requirements;
1.3. Steady-state, short-circuit, and dynamics studies, as necessary, to evaluate
system performance under both normal and contingency conditions; and
1.4. Study assumptions, system performance, alternatives considered, and
coordinated recommendations. While these studies may be performed
independently, the results shall be evaluated and coordinated by the entities
involved.

Page 1 of 9

FAC-002-3 — Facility Interconnection Studies

M1. Each Transmission Planner or each Planning Coordinator shall have evidence (such as
study reports, including documentation of reliability issues) that it met all
requirements in Requirement R1.
R2.

Each Generator Owner seeking to interconnect new generation Facilities, or to
materially modify existing interconnections of generation Facilities, shall coordinate
and cooperate on studies with its Transmission Planner or Planning Coordinator,
including but not limited to the provision of data as described in R1, Parts 1.1-1.4.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M2. Each Generator Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R2.
R3.

Each Transmission Owner and each Distribution Provider seeking to interconnect new
transmission Facilities or electricity end-user Facilities, or to materially modify existing
interconnections of transmission Facilities or electricity end-user Facilities, shall
coordinate and cooperate on studies with its Transmission Planner or Planning
Coordinator, including but not limited to the provision of data as described in R1,
Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M3. Each Transmission Owner and each Distribution Provider shall have evidence (such as
documents containing the data provided in response to the requests of the
Transmission Planner or Planning Coordinator) that it met all requirements in
Requirement R3.
R4.

Each Transmission Owner shall coordinate and cooperate with its Transmission
Planner or Planning Coordinator on studies regarding requested new or materially
modified interconnections to its Facilities, including but not limited to the provision of
data as described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

M4. Each Transmission Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R4.
R5.

Each applicable Generator Owner shall coordinate and cooperate with its
Transmission Planner or Planning Coordinator on studies regarding requested
interconnections to its Facilities, including but not limited to the provision of data as
described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon: Longterm Planning]

M5. Each applicable Generator Owner shall have evidence (such as documents containing
the data provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R5.

Page 2 of 9

FAC-002-3 — Facility Interconnection Studies

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the CEA may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Planning Coordinator, Transmission Planner, Transmission Owner,
Distribution Provider, Generator Owner and applicable Generator Owner shall
keep data or evidence to show compliance as identified below unless directed by
its CEA to retain specific evidence for a longer period of time as part of an
investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Page 3 of 9

FAC-002-3 — Facility Interconnection Studies

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

R1

Long-term
Planning

Medium The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities, but failed to
study one of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study two of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study three of the
Parts (R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator failed to
study the reliability
impact of:
interconnecting new
generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of,
generation,
transmission, or
electricity end-user
Facilities.

R2

Long-term
Planning

Medium The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

Page 4 of 9

FAC-002-3 — Facility Interconnection Studies

R#

R3

Time
Horizon

Long-term
Planning

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but
failed to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but
failed to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

failed to coordinate
and cooperate on
studies with its
Transmission Planner
or Planning
Coordinator.

Medium The Transmission
Owner or Distribution
Provider seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but

The Transmission
Owner, or Distribution
Provider seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but

The Transmission
Owner or Distribution
Provider seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but failed

The Transmission
Owner, or Distribution
Provider seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, failed to
coordinate and
cooperate on studies
with its Transmission

Page 5 of 9

FAC-002-3 — Facility Interconnection Studies

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

failed to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

failed to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

Planner or Planning
Coordinator.

R4

Long-term
Planning

Medium The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

The Transmission
Owner failed to
coordinate and
cooperate on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities.

R5

Long-term
Planning

Medium The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning

The applicable
Generator Owner
failed to coordinate
and cooperate on
studies with its
Transmission Planner

Page 6 of 9

FAC-002-3 — Facility Interconnection Studies

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

or Planning
Coordinator regarding
requested
interconnections to its
Facilities.

Page 7 of 9

FAC-002-3 — Facility Interconnection Studies

D. Regional Variances
None.

E. Interpretations
None.

F. Associated Documents
None

Page 8 of 9

Application Guidelines

Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether
an existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.

Version History
Version

Date

Action

Change
Tracking

0

April 1, 2005

Effective Date

New

0

January 13, 2006

Removed duplication of “Regional
Reliability Organizations(s).

Errata

1

August 5, 2010

Modified to address Order No. 693
Directives contained in paragraph
693.
Adopted by the NERC Board of
Trustees.

Revised

1

February 7, 2013

R2 and associated elements
approved by NERC Board of Trustees
for retirement as part of the
Paragraph 81 project (Project 201302) pending applicable regulatory
approval.

1

November 21, 2013 R2 and associated elements
approved by FERC for retirement as
part of the Paragraph 81 project
(Project 2013-02)

2

Revisions to implement the
recommendations of the FAC FiveYear Review Team.

2

August 14, 2014

Adopted by the Board of Trustees.

2

November 6, 2014

FERC letter order issued approving
FAC-002-2.

3

February 6, 2020

Adopted by NERC Board of Trustees.

Revision under
Project 2010-02

Revisions under
Project 2017-07

Page 9 of 9

Exhibit A-1
Proposed Reliability Standard FAC-002-3
Redline to Last Approved (FAC-002-2)

RELIABILITY | RESILIENCE | SECURITY

FAC-002-2 3 — Facility Interconnection Studies

A. Introduction
1.

Title:

Facility Interconnection Studies

2.

Number:

FAC-002-32

3.

Purpose: To study the impact of interconnecting new or materially modified
Facilities on the Bulk Electric System.

4.

Applicability:
4.1. Functional Entities:
4.1.1

Planning Coordinator

4.1.2

Transmission Planner

4.1.3

Transmission Owner

4.1.4

Distribution Provider

4.1.5

Generator Owner

4.1.6

Applicable Generator Owner

4.1.6.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
5.0.0 Load-Serving Entity
6.5. Effective Date: See Implementation Plan. The first day of the first calendar quarter
that is one year after the date that this 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 that is one year after
the date this standard is adopted by the NERC Board of Trustees or as otherwise
provided for in that jurisdiction.
B. Requirements and Measures
R1. Each Transmission Planner and each Planning Coordinator shall study the reliability
impact of: (i) interconnecting new generation, transmission, or electricity end-user
Facilities and (ii) materially modifying existing interconnections of generation,
transmission, or electricity end-user Facilities. The following shall be studied:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
1.1. The reliability impact of the new interconnection, or materially modified existing
interconnection, on affected system(s);
1.2. Adherence to applicable NERC Reliability Standards; regional and Transmission
Owner planning criteria; and Facility interconnection requirements;
1.3. Steady-state, short-circuit, and dynamics studies, as necessary, to evaluate system
performance under both normal and contingency conditions; and

Page 1 of 8

FAC-002-2 3 — Facility Interconnection Studies

1.4. Study assumptions, system performance, alternatives considered, and coordinated
recommendations. While these studies may be performed independently, the
results shall be evaluated and coordinated by the entities involved.
M1. Each Transmission Planner or each Planning Coordinator shall have evidence (such as
study reports, including documentation of reliability issues) that it met all requirements
in Requirement R1.
R2. Each Generator Owner seeking to interconnect new generation Facilities, or to
materially modify existing interconnections of generation Facilities, shall coordinate
and cooperate on studies with its Transmission Planner or Planning Coordinator,
including but not limited to the provision of data as described in R1, Parts 1.1-1.4.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M2. Each Generator Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R2.
R3. Each Transmission Owner, and each Distribution Provider, and each Load-Serving
Entity seeking to interconnect new transmission Facilities or electricity end-user
Facilities, or to materially modify existing interconnections of transmission Facilities
or electricity end-user Facilities, shall coordinate and cooperate on studies with its
Transmission Planner or Planning Coordinator, including but not limited to the
provision of data as described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
M3. Each Transmission Owner, and each Distribution Provider, and each Load-Serving
Entity shall have evidence (such as documents containing the data provided in response
to the requests of the Transmission Planner or Planning Coordinator) that it met all
requirements in Requirement R3.
R4. Each Transmission Owner shall coordinate and cooperate with its Transmission
Planner or Planning Coordinator on studies regarding requested new or materially
modified interconnections to its Facilities, including but not limited to the provision of
data as described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
M4. Each Transmission Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R4.
R5. Each applicable Generator Owner shall coordinate and cooperate with its Transmission
Planner or Planning Coordinator on studies regarding requested interconnections to its
Facilities, including but not limited to the provision of data as described in R1, Parts
1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M5. Each applicable Generator Owner shall have evidence (such as documents containing
the data provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R5.

Page 2 of 8

FAC-002-2 3 — Facility Interconnection Studies

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The Planning Coordinator, Transmission Planner, Transmission Owner,
Distribution Provider, Generator Owner, and applicable Generator Owner, and
Load-Serving Entity shall keep data or evidence to show compliance as identified
below unless directed by its CEA to retain specific evidence for a longer period of
time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Page 3 of 8

FAC-002-2 3 — Facility Interconnection Studies

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

R1

Long-term
Planning

Medium The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities, but failed to
study one of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study two of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study three of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator failed to
study the reliability
impact of:
interconnecting new
generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of,
generation,
transmission, or
electricity end-user
Facilities.

R2

Long-term
Planning

Medium The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,
coordinated and
cooperated on studies

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,
coordinated and
cooperated on studies

The Generator Owner
seeking to interconnect
new generation
Facilities, or to
materially modify
existing
interconnections of
generation Facilities,
coordinated and
cooperated on studies

The Generator Owner
seeking to interconnect
new generation
Facilities, or to
materially modify
existing
interconnections of
generation Facilities,
failed to coordinate
and cooperate on

Page 4 of 8

FAC-002-2 3 — Facility Interconnection Studies

R3

Long-term
Planning

with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

studies with its
Transmission Planner
or Planning
Coordinator.

Medium The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, failed to
coordinate and
cooperate on studies
with its Transmission
Planner or Planning
Coordinator.

Page 5 of 8

FAC-002-2 3 — Facility Interconnection Studies

R4

Long-term
Planning

Medium The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in one of the
Parts (R1, 1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in two of the
Parts (R1, 1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in three of
the Parts (R1, 1.1-1.4).

The Transmission
Owner failed to
coordinate and
cooperate on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities.

R5

Long-term
Planning

Medium The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in one of the
Parts (R1, 1.1-1.4).

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in two of the
Parts (R1, 1.1-1.4).

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in three of
the Parts (R1, 1.1-1.4).

The applicable
Generator Owner
failed to coordinate
and cooperate on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested
interconnections to its
Facilities.

Page 6 of 8

FAC-002-2 3 — Facility Interconnection Studies

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None

Page 7 of 8

Application Guidelines
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.

Version History

Version

Date

Action

Change
Tracking

0

April 1, 2005

Effective Date

New

0

January 13, 2006

Removed duplication of “Regional
Reliability Organizations(s).

Errata

1

August 5, 2010

Modified to address Order No. 693
Directives contained in paragraph
693.
Adopted by the NERC Board of
Trustees.

Revised

1

February 7, 2013

1

November 21, 2013

R2 and associated elements approved
by NERC Board of Trustees for
retirement as part of the Paragraph 81
project (Project 2013-02) pending
applicable regulatory approval.
R2 and associated elements approved
by FERC for retirement as part of the
Paragraph 81 project (Project 201302)

2

Revisions to implement the
recommendations of the FAC FiveYear Review Team.

Revision under
Project 2010-02

2

August 14, 2014

Adopted by the Board of Trustees.

2

November 6, 2014

FERC letter order issued approving
FAC-002-2.

3

February 6, 2020

Adopted by NERC Board of Trustees. Revisions under
Project 2017-07

Page 8 of 8

Exhibit A-2
Proposed Reliability Standard IRO-010-3
Clean

RELIABILITY | RESILIENCE | SECURITY

IRO-010-3 — Reliability Coordinator Data Specification and Collection

A. Introduction
1. Title:

Reliability Coordinator Data Specification and Collection

2. Number: IRO-010-3
3. Purpose: To prevent instability, uncontrolled separation, or Cascading outages that
adversely impact reliability, by ensuring the Reliability Coordinator has the data it needs
to monitor and assess the operation of its Reliability Coordinator Area.
4. Applicability
4.1. Reliability Coordinator.
4.2. Balancing Authority.
4.3. Generator Owner.
4.4. Generator Operator.
4.5. Transmission Operator.
4.6. Transmission Owner.
4.7. Distribution Provider.
5. Effective Date: See Implementation Plan.
B. Requirements
R1.

The Reliability Coordinator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include but not be limited to:
(Violation Risk Factor: Low) (Time Horizon: Operations Planning)
1.1.

A list of data and information needed by the Reliability Coordinator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data, as
deemed necessary by the Reliability Coordinator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

M1. The Reliability Coordinator shall make available its dated, current, in force
documented specification for data.
R2.

The Reliability Coordinator shall distribute its data specification to entities that have
data required by the Reliability Coordinator’s Operational Planning Analyses, Real-

Page 1 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

time monitoring, and Real-time Assessments. (Violation Risk Factor: Low) (Time
Horizon: Operations Planning)
M2. The Reliability Coordinator shall make available evidence that it has distributed its
data specification to entities that have data required by the Reliability Coordinator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments. This
evidence could include but is not limited to web postings with an electronic notice of
the posting, dated operator logs, voice recordings, postal receipts showing the
recipient, date and contents, or e-mail records.
R3.

Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R2 shall satisfy the obligations of the
documented specifications using: (Violation Risk Factor: Medium) (Time Horizon:
Operations Planning, Same-Day Operations, Real-time Operations)
3.1 A mutually agreeable format
3.2 A mutually agreeable process for resolving data conflicts
3.3 A mutually agreeable security protocol

M3. The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Reliability Coordinator, Transmission Operator, Transmission Owner, and
Distribution Provider receiving a data specification in Requirement R2 shall make
available evidence that it satisfied the obligations of the documented specification
using the specified criteria. Such evidence could include but is not limited to
electronic or hard copies of data transmittals or attestations of receiving entities.

Page 2 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

C. Compliance
1.

Compliance Monitoring Process
1.1.

Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2

Compliance Monitoring and Assessment Processes

As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment
Processes” refers to the identification of the processes that will be used to evaluate
data or information for the purpose of assessing performance or outcomes with the
associated reliability standard.
1.3.

Data Retention

The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
shall each keep data or evidence to show compliance as identified below unless
directed by its Compliance Enforcement Authority to retain specific evidence for a
longer period of time as part of an investigation:
The Reliability Coordinator shall retain its dated, current, in force documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments for Requirement R1,
Measure M1 as well as any documents in force since the last compliance audit.
The Reliability Coordinator shall keep evidence for three calendar years that it has
distributed its data specification to entities that have data required by the Reliability
Coordinator’s Operational Planning Analyses, Real-time monitoring, and Real-time
Assessments for Requirement R2, Measure M2.
Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
receiving a data specification shall retain evidence for the most recent 90-calendar
days that it has satisfied the obligations of the documented specifications in
accordance with Requirement R3 and Measurement M3.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.

Additional Compliance Information

None.

Page 3 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Table of Compliance Elements
R#

R1

Time
Horizon

VRF

Operations
Planning

Low

Violation Severity Levels
Lower

Moderate

High

Severe

The Reliability
Coordinator did not
include one of the
parts (Part 1.1 through
Part 1.4) of the
documented
specification for the
data necessary for it to
perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did
not include three
of the parts (Part
1.1 through Part
1.4) of the
documented
specification for
the data necessary
for it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did not
include any of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.
OR,
The Reliability
Coordinator did not
have a documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time

Page 4 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

R#

Time
Horizon

VRF

Violation Severity Levels
Lower

Moderate

High

Severe
monitoring, and
Real-time
Assessments.

For the Requirement R2 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to the
left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity has
just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R2

Operations
Planning

Low

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
one entity, or 5% or
less of the entities,
whichever is greater,
that have data
required by the
Reliability
Coordinator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
two entities, or more
than 5% and less
than or equal to 10%
of the reliability
entities, whichever is
greater, that have
data required by the
Reliability
Coordinator’s
Operational Planning
Analyses, and Realtime monitoring, and
Real-time

The Reliability
Coordinator did
not distribute its
data specification
as developed in
Requirement R1 to
three entities, or
more than 10%
and less than or
equal to 15% of the
reliability entities,
whichever is
greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
four or more
entities, or more
than 15% of the
entities, whichever
is greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Page 5 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

R#

R3

Time
Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

VRF

Violation Severity Levels
Lower

Medium

The responsible entity
receiving a data
specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for data
but failed to follow
one of the criteria
shown in Parts 3.1 –
3.3.

Moderate

High

Severe

Assessments.

monitoring, and
Real-time
Assessments.

Assessments.

The responsible
entity receiving a
data specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow two of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification
in Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow any of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification in
Requirement R2 did
not satisfy the
obligations of the
documented
specifications for
data.

Page 6 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

D. Regional Variances
None
E. Interpretations
None
F. Associated Documents
None
Version History
Version

Date

Action

Change Tracking

1

October 17, 2008

Adopted by Board of Trustees

New

1a

August 5, 2009

Added Appendix 1: Interpretation of
R1.2 and R3 as approved by Board of
Trustees

Addition

1a

March 17, 2011

Order issued by FERC approving IRO010-1a (approval effective 5/23/11)

1a
2

November 19, 2013 Updated VRFs based on June 24, 2013
approval
Revisions pursuant to Project 2014-03
April 2014

2

November 13, 2014

Adopted by NERC Board of Trustees

2

November 19, 2015

3

February 6, 2020

FERC approved IRO-010-2. Docket No.
RM15-16-000
Adopted by NERC Board of Trustees

Revisions under Project
2014-03

Revisions under Project
2017-07

Page 7 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Guidelines and Technical Basis
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 adoption, the text from the rationale
text boxes was moved to this section.
Rationale for Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to result
in an appropriate level of situational awareness. Some examples include: 1) analyzing phase
angles which may result in the implementation of an Operating Plan to adjust generation or
curtail transactions so that a Transmission facility may be returned to service, or 2) evaluating
the impact of a modified Contingency resulting from the status change of a Special Protection
Scheme from enabled/in-service to disabled/out-of-service.
Rationale for Applicability Changes:
Changes were made to applicability based on IRO FYRT recommendation to address the need for
UVLS and UFLS information in the data specification.
The Interchange Authority was removed because activities in the Coordinate Interchange
standards are performed by software systems and not a responsible entity. The software, not a
functional entity, performs the task of accepting and disseminating interchange data between
entities. The Balancing Authority is the responsible functional entity for these tasks.
The Planning Coordinator and Transmission Planner were removed from Draft 2 as those entities
would not be involved in a data specification concept as outlined in this standard.
Rationale:
Proposed Requirement R1, Part 1.1:
Is in response to issues raised in NOPR paragraph 67 on the need for obtaining non-BES and
external network data necessary for the Reliability Coordinator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2:
Is in response to NOPR paragraph 78 on relay data.
Proposed Requirement R3, Part 3.3:

Page 8 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Is in response to NOPR paragraph 92 where concerns were raised about data exchange through
secured networks.
Corresponding changes have been made to proposed TOP-003-3.

Page 9 of 9

Exhibit A-2
Proposed Reliability Standard IRO-010-3
Redline to Last Approved (IRO-010-2)

RELIABILITY | RESILIENCE | SECURITY

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

A. Introduction
1. Title:

Reliability Coordinator Data Specification and Collection

2. Number: IRO-010-32
3. Purpose: To prevent instability, uncontrolled separation, or Cascading outages that
adversely impact reliability, by ensuring the Reliability Coordinator has the data it needs
to monitor and assess the operation of its Reliability Coordinator Area.
4. Applicability
4.1. Reliability Coordinator.
4.2. Balancing Authority.
4.3. Generator Owner.
4.4. Generator Operator.
4.5. Load-Serving Entity.
4.6.4.5.

Transmission Operator.

4.7.4.6.

Transmission Owner.

4.8.4.7.

Distribution Provider.

5. Proposed Effective Date: See Implementation Plan.
6. Background
See Project 2014-03 project page.
B. Requirements
R1.

The Reliability Coordinator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include but not be limited to:
(Violation Risk Factor: Low) (Time Horizon: Operations Planning)
1.1.

A list of data and information needed by the Reliability Coordinator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data, as
deemed necessary by the Reliability Coordinator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

Page 1 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

M1. The Reliability Coordinator shall make available its dated, current, in force
documented specification for data.
R2.

The Reliability Coordinator shall distribute its data specification to entities that have
data required by the Reliability Coordinator’s Operational Planning Analyses, Realtime monitoring, and Real-time Assessments. (Violation Risk Factor: Low) (Time
Horizon: Operations Planning)

M2. The Reliability Coordinator shall make available evidence that it has distributed its
data specification to entities that have data required by the Reliability Coordinator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments. This
evidence could include but is not limited to web postings with an electronic notice of
the posting, dated operator logs, voice recordings, postal receipts showing the
recipient, date and contents, or e-mail records.
R3.

Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Operator, Transmission Owner, and
Distribution Provider receiving a data specification in Requirement R2 shall satisfy the
obligations of the documented specifications using: (Violation Risk Factor: Medium)
(Time Horizon: Operations Planning, Same-Day Operations, Real-time Operations)
3.1 A mutually agreeable format
3.2 A mutually agreeable process for resolving data conflicts
3.3 A mutually agreeable security protocol

M3. The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Reliability Coordinator, Transmission Operator,
Transmission Owner, and Distribution Provider receiving a data specification in
Requirement R2 shall make available evidence that it satisfied the obligations of the
documented specification using the specified criteria. Such evidence could include
but is not limited to electronic or hard copies of data transmittals or attestations of
receiving entities.
C. Compliance
1.

Compliance Monitoring Process
1.1.

Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2

Compliance Monitoring and Assessment Processes

As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment
Processes” refers to the identification of the processes that will be used to evaluate

Page 2 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

data or information for the purpose of assessing performance or outcomes with the
associated reliability standard.
1.3.

Data Retention

The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Operator, Transmission Owner, and
Distribution Provider shall each keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to retain
specific evidence for a longer period of time as part of an investigation:
The Reliability Coordinator shall retain its dated, current, in force documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments for Requirement R1,
Measure M1 as well as any documents in force since the last compliance audit.
The Reliability Coordinator shall keep evidence for three calendar years that it has
distributed its data specification to entities that have data required by the Reliability
Coordinator’s Operational Planning Analyses, Real-time monitoring, and Real-time
Assessments for Requirement R2, Measure M2.
Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Interchange Authority, Load-Serving Entity, Transmission Operator,
Transmission Owner, and Distribution Provider receiving a data specification shall
retain evidence for the most recent 90-calendar days that it has satisfied the
obligations of the documented specifications in accordance with Requirement R3
and Measurement M3.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.

Additional Compliance Information

None.

Page 3 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

Table of Compliance Elements
R#

R1

Time
Horizon

VRF

Operations
Planning

Low

Violation Severity Levels
Lower

Moderate

High

Severe

The Reliability
Coordinator did not
include one of the
parts (Part 1.1 through
Part 1.4) of the
documented
specification for the
data necessary for it to
perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did
not include three
of the parts (Part
1.1 through Part
1.4) of the
documented
specification for
the data necessary
for it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did not
include any of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.
OR,
The Reliability
Coordinator did not
have a documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time

Page 4 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

R#

Time
Horizon

VRF

Violation Severity Levels
Lower

Moderate

High

Severe
monitoring, and
Real-time
Assessments.

For the Requirement R2 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to the
left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity has
just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R2

Operations
Planning

Low

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
one entity, or 5% or
less of the entities,
whichever is greater,
that have data
required by the
Reliability
Coordinator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
two entities, or more
than 5% and less
than or equal to 10%
of the reliability
entities, whichever is
greater, that have
data required by the
Reliability
Coordinator’s
Operational Planning
Analyses, and Realtime monitoring, and
Real-time

The Reliability
Coordinator did
not distribute its
data specification
as developed in
Requirement R1 to
three entities, or
more than 10%
and less than or
equal to 15% of the
reliability entities,
whichever is
greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
four or more
entities, or more
than 15% of the
entities, whichever
is greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time

Page 5 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

R#

R3

Time
Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

VRF

Violation Severity Levels
Lower

Medium

The responsible entity
receiving a data
specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for data
but failed to follow
one of the criteria
shown in Parts 3.1 –
3.3.

Moderate

High

Severe

Assessments.

monitoring, and
Real-time
Assessments.

Assessments.

The responsible
entity receiving a
data specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow two of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification
in Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow any of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification in
Requirement R2 did
not satisfy the
obligations of the
documented
specifications for
data.

Page 6 of 9

IRO-010-3 — Reliability Coordinator Data Specification and CollectionStandard IRO-010-2
— Guidelines and Technical Basis

D. Regional Variances
None
E. Interpretations
None
F. Associated Documents
None
Version History
Version

Date

Action

Change Tracking

1

October 17, 2008

Adopted by Board of Trustees

New

1a

August 5, 2009

Added Appendix 1: Interpretation of
R1.2 and R3 as approved by Board of
Trustees

Addition

1a

March 17, 2011

Order issued by FERC approving IRO010-1a (approval effective 5/23/11)

1a
2

November 19, 2013 Updated VRFs based on June 24, 2013
approval
Revisions pursuant to Project 2014-03
April 2014

2

November 13, 2014

Adopted by NERC Board of Trustees

2

November 19, 2015

3

February 6, 2020

FERC approved IRO-010-2. Docket No.
RM15-16-000
Adopted by NERC Board of Trustees

Revisions under Project
2014-03

Revision under Project
2017-07

Page 7 of 9

IRO-010-3 — Reliability Coordinator Data Specification and CollectionStandard IRO-010-2
— Guidelines and Technical Basis

Guidelines and Technical Basis
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 adoption, the text from the rationale
text boxes was moved to this section.
Rationale for Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to result
in an appropriate level of situational awareness. Some examples include: 1) analyzing phase
angles which may result in the implementation of an Operating Plan to adjust generation or
curtail transactions so that a Transmission facility may be returned to service, or 2) evaluating
the impact of a modified Contingency resulting from the status change of a Special Protection
Scheme from enabled/in-service to disabled/out-of-service.
Rationale for Applicability Changes:
Changes were made to applicability based on IRO FYRT recommendation to address the need for
UVLS and UFLS information in the data specification.
The Interchange Authority was removed because activities in the Coordinate Interchange
standards are performed by software systems and not a responsible entity. The software, not a
functional entity, performs the task of accepting and disseminating interchange data between
entities. The Balancing Authority is the responsible functional entity for these tasks.
The Planning Coordinator and Transmission Planner were removed from Draft 2 as those entities
would not be involved in a data specification concept as outlined in this standard.
Rationale:
Proposed Requirement R1, Part 1.1:
Is in response to issues raised in NOPR paragraph 67 on the need for obtaining non-BES and
external network data necessary for the Reliability Coordinator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2:
Is in response to NOPR paragraph 78 on relay data.
Proposed Requirement R3, Part 3.3:
Page 8 of 9

IRO-010-3 — Reliability Coordinator Data Specification and CollectionStandard IRO-010-2
— Guidelines and Technical Basis

Is in response to NOPR paragraph 92 where concerns were raised about data exchange through
secured networks.
Corresponding changes have been made to proposed TOP-003-3.

Page 9 of 9

Exhibit A-3
Proposed Reliability Standard MOD-031-3
Clean

RELIABILITY | RESILIENCE | SECURITY

MOD-031-3 — Demand and Energy Data

A. Introduction
1. Title:

Demand and Energy Data

2. Number:

MOD-031-3

3. Purpose:
To provide authority for applicable entities to collect Demand, energy
and related data to support reliability studies and assessments and to enumerate the
responsibilities and obligations of requestors and respondents of that data.
4. Applicability:
4.1.

Functional Entities:
4.1.1 Planning Coordinator
4.1.2 Transmission Planner
4.1.3 Balancing Authority
4.1.4 Resource Planner
4.1.5 Distribution Provider

5. Effective Date: See Implementation Plan.
B. Requirements and Measures
R1.

Each Planning Coordinator or Balancing Authority that identifies a need for the
collection of Total Internal Demand, Net Energy for Load, and Demand Side
Management data shall develop and issue a data request to the applicable entities in
its area. The data request shall include: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
1.1. A list of Transmission Planners, Balancing Authorities, and Distribution Providers
that are required to provide the data (“Applicable Entities”).
1.2. A timetable for providing the data. (A minimum of 30 calendar days must be
allowed for responding to the request).
1.3. A request to provide any or all of the following actual data, as necessary:
1.3.1. Integrated hourly Demands in megawatts for the prior calendar year.
1.3.2. Monthly and annual integrated peak hour Demands in megawatts for the
prior calendar year.
1.3.2.1.

If the annual peak hour actual Demand varies due to weatherrelated conditions (e.g., temperature, humidity or wind
speed), the Applicable Entity shall also provide the weather
normalized annual peak hour actual Demand for the prior
calendar year.

Page 1 of 11

MOD-031-3 — Demand and Energy Data

1.3.3. Monthly and annual Net Energy for Load in gigawatt hours for the prior
calendar year.
1.3.4. Monthly and annual peak hour controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator in megawatts for the prior calendar year. Three values shall be
reported for each hour: 1) the committed megawatts (the amount under
control or supervision), 2) the dispatched megawatts (the amount, if any,
activated for use by the System Operator), and 3) the realized megawatts
(the amount of actual demand reduction).
1.4. A request to provide any or all of the following forecast data, as necessary:
1.4.1. Monthly peak hour forecast Total Internal Demands in megawatts for the
next two calendar years.
1.4.2. Monthly forecast Net Energy for Load in gigawatthours for the next two
calendar years.
1.4.3. Peak hour forecast Total Internal Demands (summer and winter) in
megawatts for ten calendar years into the future.
1.4.4. Annual forecast Net Energy for Load in gigawatthours for ten calendar
years into the future.
1.4.5. Total and available peak hour forecast of controllable and dispatchable
Demand Side Management (summer and winter), in megawatts, under
the control or supervision of the System Operator for ten calendar years
into the future.
1.5. A request to provide any or all of the following summary explanations, as
necessary,:
1.5.1. The assumptions and methods used in the development of aggregated
Peak Demand and Net Energy for Load forecasts.
1.5.2. The Demand and energy effects of controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator.
1.5.3. How Demand Side Management is addressed in the forecasts of its Peak
Demand and annual Net Energy for Load.
1.5.4. How the controllable and dispatchable Demand Side Management
forecast compares to actual controllable and dispatchable Demand Side
Management for the prior calendar year and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
1.5.5. How the peak Demand forecast compares to actual Demand for the prior
calendar year with due regard to any relevant weather-related variations

Page 2 of 11

MOD-031-3 — Demand and Energy Data

(e.g., temperature, humidity, or wind speed) and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
M1. The Planning Coordinator or Balancing Authority shall have a dated data request,
either in hardcopy or electronic format, in accordance with Requirement R1.
R2.

Each Applicable Entity identified in a data request shall provide the data requested by
its Planning Coordinator or Balancing Authority in accordance with the data request
issued pursuant to Requirement R1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

M2. Each Applicable Entity shall have evidence, such as dated e-mails or dated transmittal
letters that it provided the requested data in accordance with Requirement R2.
R3.

The Planning Coordinator or the Balancing Authority shall provide the data listed
under Requirement R1 Parts 1.3 through 1.5 for their area to the applicable Regional
Entity within 75 calendar days of receiving a request for such data, unless otherwise
agreed upon by the parties. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]

M3. Each Planning Coordinator or Balancing Authority, shall have evidence, such as dated
e-mails or dated transmittal letters that it provided the data requested by the
applicable Regional Entity in accordance with Requirement R3.
R4.

Any Applicable Entity shall, in response to a written request for the data included in
parts 1.3-1.5 of Requirement R1 from a Planning Coordinator, Balancing Authority,
Transmission Planner or Resource Planner with a demonstrated need for such data in
order to conduct reliability assessments of the Bulk Electric System, provide or
otherwise make available that data to the requesting entity. This requirement does
not modify an entity’s obligation pursuant to Requirement R2 to respond to data
requests issued by its Planning Coordinator or Balancing Authority pursuant to
Requirement R1. Unless otherwise agreed upon, the Applicable Entity: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
•

shall not be required to alter the format in which it maintains or uses the data;

•

shall provide the requested data within 45 calendar days of the written
request, subject to part 4.1 of this requirement; unless providing the
requested data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements

4.1. If the Applicable Entity does not provide data requested because (1) the
requesting entity did not demonstrate a reliability need for the data; or (2)
providing the data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements, the Applicable Entity shall, within 30
calendar days of the written request, provide a written response to the
requesting entity specifying the data that is not being provided and on what
basis.

Page 3 of 11

MOD-031-3 — Demand and Energy Data

M4. Each Applicable Entity identified in Requirement R4 shall have evidence such as dated
e-mails or dated transmittal letters that it provided the data requested or provided a
written response specifying the data that is not being provided and the basis for not
providing the data in accordance with Requirement R4.

Page 4 of 11

MOD-031-3 — Demand and Energy Data

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The Applicable Entity shall keep data or evidence to show compliance with
Requirements R1 through R4, and Measures M1 through M4, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an Applicable Entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Page 5 of 11

MOD-031-3 — Demand and Energy Data

Table of Compliance Elements
R#

Time Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

N/A

N/A

N/A

The Planning Coordinator
or Balancing Authority
developed and issued a
data request but failed to
include either the entity(s)
necessary to provide the
data or the timetable for
providing the data.

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.3.1 through part
1.3.4

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.4.1 through part
1.4.5

R1

Long-term
Planning

Medium

R2

Long-term
Planning

Medium The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide all of the
data requested in
Requirement R1 part
1.5.1 through part
1.5.5

High VSL

Severe VSL

OR

Page 6 of 11

MOD-031-3 — Demand and Energy Data

did so after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 6 days
after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

R3

Long-term
Planning

Medium The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 75 days

1.4.1 through part
1.4.5

1.4.1 through part
1.4.5

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but
did so 6 days after the
date indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 11
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Applicable Entity, as
defined in the data request
The Applicable Entity, developed in Requirement
R1, failed to provide the
as defined in the data
data requested in the
request developed in
timetable provided
Requirement R1,
pursuant to Requirement
provided the data
R1 prior to 16 days after
requested in
the date indicated in the
Requirement R1, but
timetable provided
did so 11 days after
pursuant to Requirement
the date indicated in
the timetable provided R1 part 1.2.
pursuant to
Requirement R1 part
1.2 but prior to 15
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 80 days

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 85 days

The Planning Coordinator
or Balancing Authority, in
response to a request by
the Regional Entity, failed
to make available the data
requested prior to 91 days

Page 7 of 11

MOD-031-3 — Demand and Energy Data

R4

Long-term
Planning

from the date of
request but prior to 81
days from the date of
the request.

from the date of
request but prior to 86
days from the date of
the request.

from the date of
request but prior to 91
days from the date of
the request.

or more from the date of
the request.

Medium The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
45 days from the date
of request but prior to
51 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
50 days from the date
of request but prior to
56 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
55 days from the date
of request but prior to
61 days from the date
of the request

The Applicable Entity failed
to provide or otherwise
make available the data to
the requesting entity
within 60 days from the
date of the request

OR

OR

OR

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 30 days of the
written request but
prior to 36 days of the
written request.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 35 days of the
written request but
prior to 41 days of the
written request.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 40 days of the
written request but
prior to 46 days of the
written request.

OR
The Applicable Entity that
is not providing the data
requested failed to provide
a written response
specifying the data that is
not being provided and on
what basis within 45 days
of the written request.

Page 8 of 11

MOD-031-3 — Demand and Energy Data

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

Action

1

May 6, 2014

1

February 19,
2015

Adopted by the NERC Board
of Trustees
FERC order approving MOD031-1

2

November 5,
2015

Adopted by the NERC Board
of Trustees

2

February 18,
2016

FERC order approving MOD031-2. Docket No. RD16-1000

3

February 6,
2020

Adopted by the NERC Board
of Trustees

Change Tracking

Revisions under Project 201707

Page 9 of 11

MOD-031-3 — Demand and Energy Data

Guidelines and Technical Basis
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:
Rationale for R1: To ensure that when Planning Coordinators (PCs) or Balancing Authorities
(BAs) request data (R1), they identify the entities that must provide the data (Applicable Entity
in part 1.1), the data to be provided (parts 1.3 – 1.5) and the due dates (part 1.2) for the
requested data.
For Requirement R1 part 1.3.2.1, if the Demand does not vary due to weather-related
conditions (e.g., temperature, humidity or wind speed), or the weather assumed in the forecast
was the same as the actual weather, the weather normalized actual Demand will be the same
as the actual demand reported for Requirement R1 part 1.3.2. Otherwise the annual peak hour
weather normalized actual Demand will be different from the actual demand reported for
Requirement R1 part 1.3.2.
Balancing Authorities are included here to reflect a practice in the WECC Region where BAs are
the entity that perform this requirement in lieu of the PC.
Rationale for R2:
This requirement will ensure that entities identified in Requirement R1, as responsible for
providing data, provide the data in accordance with the details described in the data request
developed in accordance with Requirement R1. In no event shall the Applicable Entity be
required to provide data under this requirement that is outside the scope of parts 1.3 - 1.5 of
Requirement R1.
Rationale for R3:
This requirement will ensure that the Planning Coordinator or when applicable, the Balancing
Authority, provides the data requested by the Regional Entity.
Rationale for R4:
This requirement will ensure that the Applicable Entity will make the data requested by the
Planning Coordinator or Balancing Authority in Requirement R1 available to other applicable
entities (Planning Coordinator, Balancing Authority, Transmission Planner or Resource Planner)
unless providing the data would conflict with the Applicable Entity’s confidentiality, regulatory,
or security requirements. The sharing of documentation of the supporting methods and
assumptions used to develop forecasts as well as information-sharing activities will improve the
efficiency of planning practices and support the identification of needed system
reinforcements.

Page 10 of 11

MOD-031-3 — Demand and Energy Data

The obligation to share data under Requirement R4 does not supersede or otherwise modify
any of the Applicable Entity’s existing confidentiality obligations. For instance, if an entity is
prohibited from providing any of the requested data pursuant to confidentiality provisions of an
Open Access Transmission Tariff or a contractual arrangement, Requirement R4 does not
require the Applicable Entity to provide the data to a requesting entity. Rather, under Part 4.1,
the Applicable Entity must simply provide written notification to the requesting entity that it
will not be providing the data and the basis for not providing the data. If the Applicable Entity is
subject to confidentiality obligations that allow the Applicable Entity to share the data only if
certain conditions are met, the Applicable Entity shall ensure that those conditions are met
within the 45-day time period provided in Requirement R4, communicate with the requesting
entity regarding an extension of the 45-day time period so as to meet all those conditions, or
provide justification under Part 4.1 as to why those conditions cannot be met under the
circumstances.

Page 11 of 11

Exhibit A-3
Proposed Reliability Standard MOD-031-3
Redline to Last Approved (MOD-031-2)

RELIABILITY | RESILIENCE | SECURITY

MOD-031-2 3 — Demand and Energy Data

A. Introduction
1.

Title: Demand and Energy Data

2.

Number:

3.

Purpose: To provide authority for applicable entities to collect Demand, energy
and related data to support reliability studies and assessments and to enumerate the
responsibilities and obligations of requestors and respondents of that data.

4.

Applicability:

MOD-031-23

4.1. Functional Entities:
4.1.1 Planning Authority and Planning Coordinator (hereafter collectively
referred to as the “Planning Coordinator”)
4.1.24.1.1
This proposed standard combines “Planning Authority” with
“Planning Coordinator” in the list of applicable functional entities. The
NERC Functional Model lists “Planning Coordinator” while the
registration criteria list “Planning Authority,” and they are not yet
synchronized. Until that occurs, the proposed standard applies to both
“Planning Authority” and “Planning Coordinator.”
4.1.34.1.2

Transmission Planner

4.1.44.1.3

Balancing Authority

4.1.54.1.4

Resource Planner

4.1.6 Load-Serving Entity
4.1.74.1.5

Distribution Provider

5.

Effective Date: See the MOD-031-2 Implementation Plan.

6.

Background:
To ensure that various forms of historical and forecast Demand and energy data and
information is available to the parties that perform reliability studies and
assessments, authority is needed to collect the applicable data.
The collection of Demand, Net Energy for Load and Demand Side Management data
requires coordination and collaboration between Planning Authorities (Planning
Coordinators), Transmission and Resource Planners, Load-Serving Entities and
Distribution Providers. Ensuring that planners and operators have access to complete
and accurate load forecasts – as well as the supporting methods and assumptions
used to develop these forecasts – enhances the reliability of the Bulk Electric System.
Consistent documenting and information sharing activities will also improve efficient
planning practices and support the identification of needed system reinforcements.
Furthermore, collection of actual Demand and Demand Side Management
performance during the prior year will allow for comparison to prior forecasts and
further contribute to enhanced accuracy of load forecasting practices.

Page 1 of 11

MOD-031-2 3 — Demand and Energy Data

Data provided under this standard is generally considered confidential by Planning
Coordinators and Balancing Authorities receiving the data. Furthermore, data
reported to a Regional Entity is subject to the confidentiality provisions in Section
1500 of the North American Electric Reliability Corporation Rules of Procedure and is
typically aggregated with data of other functional entities in a non-attributable
manner. While this standard allows for the sharing of data necessary to perform
certain reliability studies and assessments, any data received under this standard for
which an applicable entity has made a claim of confidentiality should be maintained
as confidential by the receiving entity.
B. Requirements and Measures
R1.

Each Planning Coordinator or Balancing Authority that identifies a need for the
collection of Total Internal Demand, Net Energy for Load, and Demand Side
Management data shall develop and issue a data request to the applicable entities in
its area. The data request shall include: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
1.1. A list of Transmission Planners, Balancing Authorities, Load Serving Entities, and
Distribution Providers that are required to provide the data (“Applicable
Entities”).
1.2. A timetable for providing the data. (A minimum of 30 calendar days must be
allowed for responding to the request).
1.3. A request to provide any or all of the following actual data, as necessary:
1.3.1. Integrated hourly Demands in megawatts for the prior calendar year.
1.3.2. Monthly and annual integrated peak hour Demands in megawatts for the
prior calendar year.
1.3.2.1.

If the annual peak hour actual Demand varies due to weatherrelated conditions (e.g., temperature, humidity or wind
speed), the Applicable Entity shall also provide the weather
normalized annual peak hour actual Demand for the prior
calendar year.

1.3.3. Monthly and annual Net Energy for Load in gigawatthours for the prior
calendar year.
1.3.4. Monthly and annual peak hour controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator in megawatts for the prior calendar year. Three values shall be
reported for each hour: 1) the committed megawatts (the amount under
control or supervision), 2) the dispatched megawatts (the amount, if any,
activated for use by the System Operator), and 3) the realized megawatts
(the amount of actual demand reduction).

Page 2 of 11

MOD-031-2 3 — Demand and Energy Data

1.4. A request to provide any or all of the following forecast data, as necessary:
1.4.1. Monthly peak hour forecast Total Internal Demands in megawatts for the
next two calendar years.
1.4.2. Monthly forecast Net Energy for Load in gigawatthours for the next two
calendar years.
1.4.3. Peak hour forecast Total Internal Demands (summer and winter) in
megawatts for ten calendar years into the future.
1.4.4. Annual forecast Net Energy for Load in gigawatthours for ten calendar
years into the future.
1.4.5. Total and available peak hour forecast of controllable and dispatchable
Demand Side Management (summer and winter), in megawatts, under
the control or supervision of the System Operator for ten calendar years
into the future.
1.5. A request to provide any or all of the following summary explanations, as
necessary,:
1.5.1. The assumptions and methods used in the development of aggregated
Peak Demand and Net Energy for Load forecasts.
1.5.2. The Demand and energy effects of controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator.
1.5.3. How Demand Side Management is addressed in the forecasts of its Peak
Demand and annual Net Energy for Load.
1.5.4. How the controllable and dispatchable Demand Side Management
forecast compares to actual controllable and dispatchable Demand Side
Management for the prior calendar year and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
1.5.5. How the peak Demand forecast compares to actual Demand for the prior
calendar year with due regard to any relevant weather-related variations
(e.g., temperature, humidity, or wind speed) and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
M1. The Planning Coordinator or Balancing Authority shall have a dated data request,
either in hardcopy or electronic format, in accordance with Requirement R1.
R2.

Each Applicable Entity identified in a data request shall provide the data requested by
its Planning Coordinator or Balancing Authority in accordance with the data request
issued pursuant to Requirement R1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

M2. Each Applicable Entity shall have evidence, such as dated e-mails or dated transmittal
letters that it provided the requested data in accordance with Requirement R2.

Page 3 of 11

MOD-031-2 3 — Demand and Energy Data

R3.

The Planning Coordinator or the Balancing Authority shall provide the data listed
under Requirement R1 Parts 1.3 through 1.5 for their area to the applicable Regional
Entity within 75 calendar days of receiving a request for such data, unless otherwise
agreed upon by the parties. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]

M3. Each Planning Coordinator or Balancing Authority, shall have evidence, such as dated
e-mails or dated transmittal letters that it provided the data requested by the
applicable Regional Entity in accordance with Requirement R3.
R4.

Any Applicable Entity shall, in response to a written request for the data included in
parts 1.3-1.5 of Requirement R1 from a Planning Coordinator, Balancing Authority,
Transmission Planner or Resource Planner with a demonstrated need for such data in
order to conduct reliability assessments of the Bulk Electric System, provide or
otherwise make available that data to the requesting entity. This requirement does
not modify an entity’s obligation pursuant to Requirement R2 to respond to data
requests issued by its Planning Coordinator or Balancing Authority pursuant to
Requirement R1. Unless otherwise agreed upon, the Applicable Entity: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
•

shall not be required to alter the format in which it maintains or uses the data;

•

shall provide the requested data within 45 calendar days of the written
request, subject to part 4.1 of this requirement; unless providing the
requested data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements

4.1. If the Applicable Entity does not provide data requested because (1) the
requesting entity did not demonstrate a reliability need for the data; or (2)
providing the data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements, the Applicable Entity shall, within 30
calendar days of the written request, provide a written response to the
requesting entity specifying the data that is not being provided and on what
basis.
M4. Each Applicable Entity identified in Requirement R4 shall have evidence such as dated
e-mails or dated transmittal letters that it provided the data requested or provided a
written response specifying the data that is not being provided and the basis for not
providing the data in accordance with Requirement R4.

Page 4 of 11

MOD-031-2 3 — Demand and Energy Data

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The Applicable Entity shall keep data or evidence to show compliance with
Requirements R1 through R4, and Measures M1 through M4, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an Applicable Entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Page 5 of 11

MOD-031-2 3 — Demand and Energy Data

Table of Compliance Elements
R#

Time Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

N/A

N/A

N/A

The Planning Coordinator
or Balancing Authority
developed and issued a
data request but failed to
include either the entity(s)
necessary to provide the
data or the timetable for
providing the data.

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.3.1 through part
1.3.4

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.4.1 through part
1.4.5

R1

Long-term
Planning

Medium

R2

Long-term
Planning

Medium The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide all of the
data requested in
Requirement R1 part
1.5.1 through part
1.5.5

High VSL

Severe VSL

OR

Page 6 of 11

MOD-031-2 3 — Demand and Energy Data

did so after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 6 days
after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

R3

Long-term
Planning

Medium The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 75 days

1.4.1 through part
1.4.5

1.4.1 through part
1.4.5

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but
did so 6 days after the
date indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 11
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Applicable Entity, as
defined in the data request
The Applicable Entity, developed in Requirement
R1, failed to provide the
as defined in the data
data requested in the
request developed in
timetable provided
Requirement R1,
pursuant to Requirement
provided the data
R1 prior to 16 days after
requested in
the date indicated in the
Requirement R1, but
timetable provided
did so 11 days after
pursuant to Requirement
the date indicated in
the timetable provided R1 part 1.2.
pursuant to
Requirement R1 part
1.2 but prior to 15
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 80 days

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 85 days

The Planning Coordinator
or Balancing Authority, in
response to a request by
the Regional Entity, failed
to make available the data
requested prior to 91 days

Page 7 of 11

MOD-031-2 3 — Demand and Energy Data

R4

Long-term
Planning

from the date of
request but prior to 81
days from the date of
the request.

from the date of
request but prior to 86
days from the date of
the request.

from the date of
request but prior to 91
days from the date of
the request.

or more from the date of
the request.

Medium The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
45 days from the date
of request but prior to
51 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
50 days from the date
of request but prior to
56 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
55 days from the date
of request but prior to
61 days from the date
of the request

The Applicable Entity failed
to provide or otherwise
make available the data to
the requesting entity
within 60 days from the
date of the request

OR

OR

OR

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 30 days of the
written request but
prior to 36 days of the
written resquest.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 35 days of the
written request but
prior to 41 days of the
written resquest.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 40 days of the
written request but
prior to 46 days of the
written resquest.

OR
The Applicable Entity that
is not providing the data
requested failed to provide
a written response
specifying the data that is
not being provided and on
what basis within 45 days
of the written resquest.

Page 8 of 11

MOD-031-2 3 — Demand and Energy Data

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

Action

1

May 6, 2014

1

February 19,
2015

Adopted by the NERC Board
of Trustees
FERC order approving MOD031-1

2

November 5,
2015

Adopted by the NERC Board
of Trustees

2

February 18,
2016

FERC order approving MOD031-2. Docket No. RD16-1000

3

February 6,
2020

Adopted by the NERC Board
of Trustees

Change Tracking

Revisions under Project 201707

Page 9 of 11

MOD-031-3 — Demand and Energy DataApplication Guidelines
Guidelines and Technical Basis
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:
Rationale for R1: To ensure that when Planning Coordinators (PCs) or Balancing Authorities
(BAs) request data (R1), they identify the entities that must provide the data (Applicable Entity
in part 1.1), the data to be provided (parts 1.3 – 1.5) and the due dates (part 1.2) for the
requested data.
For Requirement R1 part 1.3.2.1, if the Demand does not vary due to weather-related
conditions (e.g., temperature, humidity or wind speed), or the weather assumed in the forecast
was the same as the actual weather, the weather normalized actual Demand will be the same
as the actual demand reported for Requirement R1 part 1.3.2. Otherwise the annual peak hour
weather normalized actual Demand will be different from the actual demand reported for
Requirement R1 part 1.3.2.
Balancing Authorities are included here to reflect a practice in the WECC Region where BAs are
the entity that perform this requirement in lieu of the PC.
Rationale for R2:
This requirement will ensure that entities identified in Requirement R1, as responsible for
providing data, provide the data in accordance with the details described in the data request
developed in accordance with Requirement R1. In no event shall the Applicable Entity be
required to provide data under this requirement that is outside the scope of parts 1.3 - 1.5 of
Requirement R1.
Rationale for R3:
This requirement will ensure that the Planning Coordinator or when applicable, the Balancing
Authority, provides the data requested by the Regional Entity.
Rationale for R4:
This requirement will ensure that the Applicable Entity will make the data requested by the
Planning Coordinator or Balancing Authority in Requirement R1 available to other applicable
entities (Planning Coordinator, Balancing Authority, Transmission Planner or Resource Planner)
unless providing the data would conflict with the Applicable Entity’s confidentiality, regulatory,
or security requirements. The sharing of documentation of the supporting methods and
assumptions used to develop forecasts as well as information-sharing activities will improve the
efficiency of planning practices and support the identification of needed system
reinforcements.

Page 10 of 11

MOD-031-3 — Demand and Energy DataApplication Guidelines

The obligation to share data under Requirement R4 does not supersede or otherwise modify
any of the Applicable Entity’s existing confidentiality obligations. For instance, if an entity is
prohibited from providing any of the requested data pursuant to confidentiality provisions of an
Open Access Transmission Tariff or a contractual arrangement, Requirement R4 does not
require the Applicable Entity to provide the data to a requesting entity. Rather, under Part 4.1,
the Applicable Entity must simply provide written notification to the requesting entity that it
will not be providing the data and the basis for not providing the data. If the Applicable Entity is
subject to confidentiality obligations that allow the Applicable Entity to share the data only if
certain conditions are met, the Applicable Entity shall ensure that those conditions are met
within the 45-day time period provided in Requirement R4, communicate with the requesting
entity regarding an extension of the 45-day time period so as to meet all those conditions, or
provide justification under Part 4.1 as to why those conditions cannot be met under the
circumstances.

Page 11 of 11

Exhibit A-4
Proposed Reliability Standard MOD-033-2
Clean

RELIABILITY | RESILIENCE | SECURITY

MOD-033-2 — Steady-State and Dynamic System Model Validation

A. Introduction
1.

Title: Steady-State and Dynamic System Model Validation

2.

Number:

3.

Purpose:
To establish consistent validation requirements to facilitate the
collection of accurate data and building of planning models to analyze the reliability of
the interconnected transmission system.

4.

Applicability:

MOD-033-2

4.1. Functional Entities:
4.1.1 Planning Coordinator
4.1.2 Reliability Coordinator
4.1.3 Transmission Operator
5.

Effective Date: See Implementation Plan.

Page 1 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

B. Requirements and Measures
R1.

Each Planning Coordinator shall implement a documented data validation process
that includes the following attributes: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
1.1. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning power flow model to actual system behavior,
represented by a state estimator case or other Real-time data sources, at least
once every 24 calendar months through simulation;
1.2. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning dynamic model to actual system response, through
simulation of a dynamic local event, at least once every 24 calendar months (use
a dynamic local event that occurs within 24 calendar months of the last dynamic
local event used in comparison, and complete each comparison within 24
calendar months of the dynamic local event). If no dynamic local event occurs
within the 24 calendar months, use the next dynamic local event that occurs;
1.3. Guidelines the Planning Coordinator will use to determine unacceptable
differences in performance under Part 1.1 or 1.2; and
1.4. Guidelines to resolve the unacceptable differences in performance identified
under Part 1.3.

M1. Each Planning Coordinator shall provide evidence that it has a documented validation

process according to Requirement R1 as well as evidence that demonstrates the
implementation of the required components of the process.

R2.

Each Reliability Coordinator and Transmission Operator shall provide actual system
behavior data (or a written response that it does not have the requested data) to any
Planning Coordinator performing validation under Requirement R1 within 30 calendar
days of a written request, such as, but not limited to, state estimator case or other
Real-time data (including disturbance data recordings) necessary for actual system
response validation. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

M2. Each Reliability Coordinator and Transmission Operator shall provide evidence, such

as email notices or postal receipts showing recipient and date that it has distributed
the requested data or written response that it does not have the data, to any Planning
Coordinator performing validation under Requirement R1 within 30 days of a written
request in accordance with Requirement R2; or a statement by the Reliability
Coordinator or Transmission Operator that it has not received notification regarding
data necessary for validation by any Planning Coordinator.

Page 2 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity in their
respective roles of monitoring and enforcing compliance with the NERC
Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance with
Requirements R1 through R2, and Measures M1 through M2, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an applicable entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Refer to Section 3.0 of Appendix 4C of the NERC Rules of Procedure for a list of
compliance monitoring and assessment processes.
1.4. Additional Compliance Information
None

Page 3 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

Table of Compliance Elements
R#

Time Horizon

Violation Severity Levels

VRF
Lower VSL

R1

Long-term
Planning

Medium The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address one of the
four required topics
under Requirement
R1;

Moderate VSL

High VSL

Severe VSL

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address two of the
four required topics
under Requirement
R1;

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address three of the
four required topics
under Requirement
R1;

The Planning
Coordinator did not
have a validation
process at all or did
not document or
implement any of the
four required topics
under Requirement
R1;

OR

OR

OR

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation within 28
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months;

The Planning
Coordinator did not
validate its portion of
the system in the
power flow model as
required by part 1.1
within 36 calendar
months;

OR

OR

OR
The Planning
Coordinator did not
perform simulation as

Page 4 of 10

OR

OR
The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 36 calendar

MOD-033-2 — Steady-State and Dynamic System Model Validation
R#

R2

Time Horizon

Long-term
Planning

Violation Severity Levels

VRF

Lower

Lower VSL

Moderate VSL

High VSL

Severe VSL

required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation within 28
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months.

months (or the next
dynamic local event in
cases where there is
more than 24 months
between events).

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning

Page 5 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation
R#

Time Horizon

Violation Severity Levels

VRF
Lower VSL

Moderate VSL

High VSL

Severe VSL

Coordinator within 30
calendar days of the
written request, but
did provide the data
(or written response
that it does not have
the requested data) in
less than or equal to
45 calendar days.

Coordinator within 30
calendar days of the
written request, but
did provide the data
(or written response
that it does not have
the requested data) in
greater than 45
calendar days but less
than or equal to 60
calendar days.

Coordinator within 30
calendar days of the
written request, but
did provide the data
(or written response
that it does not have
the requested data) in
greater than 60
calendar days but less
than or equal to 75
calendar days.

Coordinator within 75
calendar days;

D. Regional Variances
None.

E. Interpretations
None.

F. Associated Documents
None.

Page 6 of 10

OR
The Reliability
Coordinator or
Transmission Operator
provided a written
response that it does
not have the
requested data, but
actually had the data.

MOD-033-2 — Steady-State and Dynamic System Model Validation

Guidelines and Technical Basis
Requirement R1:
The requirement focuses on the results-based outcome of developing a process for and
performing a validation, but does not prescribe a specific method or procedure for the
validation outside of the attributes specified in the requirement. For further information on
suggested validation procedures, see “Procedures for Validation of Powerflow and Dynamics
Cases” produced by the NERC Model Working Group.
The specific process is left to the judgment of the Planning Coordinator, but the Planning
Coordinator is required to develop and include in its process guidelines for evaluating
discrepancies between actual system behavior or response and expected system performance
for determining whether the discrepancies are unacceptable.
For the validation in part 1.1, the state estimator case or other Real-time data should be taken
as close to system peak as possible. However, other snapshots of the system could be used if
deemed to be more appropriate by the Planning Coordinator. While the requirement specifies
“once every 24 calendar months,” entities are encouraged to perform the comparison on a
more frequent basis.
In performing the comparison required in part 1.1, the Planning Coordinator may consider,
among other criteria:
1. System load;
2. Transmission topology and parameters;
3. Voltage at major buses; and
4. Flows on major transmission elements.
The validation in part 1.1 would include consideration of the load distribution and load power
factors (as applicable) used in the power flow models. The validation may be made using
metered load data if state estimator cases are not available. The comparison of system load
distribution and load power factors shall be made on an aggregate company or power flow
zone level at a minimum but may also be made on a bus by bus, load pocket (e.g., within a
Balancing Authority), or smaller area basis as deemed appropriate by the Planning Coordinator.
The scope of dynamics model validation is intended to be limited, for purposes of part 1.2, to
the Planning Coordinator’s planning area, and the intended emphasis under the requirement is
on local events or local phenomena, not the whole Interconnection.
The validation required in part 1.2 may include simulations that are to be compared with actual
system data and may include comparisons of:
•

Voltage oscillations at major buses

•

System frequency (for events with frequency excursions)

•

Real and reactive power oscillations on generating units and major inter-area ties

Page 7 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

Determining when a dynamic local event might occur may be unpredictable, and because of the
analytic complexities involved in simulation, the time parameters in part 1.2 specify that the
comparison period of “at least once every 24 calendar months” is intended to both provide for
at least 24 months between dynamic local events used in the comparisons and that
comparisons must be completed within 24 months of the date of the dynamic local event used.
This clarification ensures that PCs will not face a timing scenario that makes it impossible to
comply. If the time referred to the completion time of the comparison, it would be possible for
an event to occur in month 23 since the last comparison, leaving only one month to complete
the comparison. With the 30 day timeframe in Requirement R2 for TOPs or RCs to provide
actual system behavior data (if necessary in the comparison), it would potentially be impossible
to complete the comparison within the 24 month timeframe.
In contrast, the requirement language clarifies that the time frame between dynamic local
events used in the comparisons should be within 24 months of each other (or, as specified at
the end of part 1.2, in the event more than 24 months passes before the next dynamic local
event, the comparison should use the next dynamic local event that occurs). Each comparison
must be completed within 24 months of the dynamic local event used. In this manner, the
potential problem with a “month 23” dynamic local event described above is resolved. For
example, if a PC uses for comparison a dynamic local event occurring on day 1 of month 1, the
PC has 24 calendar months from that dynamic local event’s occurrence to complete the
comparison. If the next dynamic event the PC chooses for comparison occurs in month 23, the
PC has 24 months from that dynamic local event’s occurrence to complete the comparison.
Part 1.3 requires the PC to include guidelines in its documented validation process for
determining when discrepancies in the comparison of simulation results with actual system
results are unacceptable. The PC may develop the guidelines required by parts 1.3 and 1.4
itself, reference other established guidelines, or both. For the power flow comparison, as an
example, this could include a guideline the Planning Coordinator will use that flows on 500 kV
lines should be within 10% or 100 MW, whichever is larger. It could be different percentages or
MW amounts for different voltage levels. Or, as another example, the guideline for voltage
comparisons could be that it must be within 1%. But the guidelines the PC includes within its
documented validation process should be meaningful for the Planning Coordinator’s system.
Guidelines for the dynamic event comparison may be less precise. Regardless, the comparison
should indicate that the conclusions drawn from the two results should be consistent. For
example, the guideline could state that the simulation result will be plotted on the same graph
as the actual system response. Then the two plots could be given a visual inspection to see if
they look similar or not. Or a guideline could be defined such that the rise time of the transient
response in the simulation should be within 20% of the rise time of the actual system response.
As for the power flow guidelines, the dynamic comparison criteria should be meaningful for the
Planning Coordinator’s system.
The guidelines the PC includes in its documented validation process to resolve differences in
Part 1.4 could include direct coordination with the data owner, and, if necessary, through the
provisions of MOD-032-1, Requirement R3 (i.e., the validation performed under this
requirement could identify technical concerns with the data). In other words, while this
standard is focused on validation, results of the validation may identify data provided under the
Page 8 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

modeling data standard that needs to be corrected. If a model with estimated data or a generic
model is used for a generator, and the model response does not match the actual response,
then the estimated data should be corrected or a more detailed model should be requested
from the data provider.
While the validation is focused on the Planning Coordinator’s planning area, the model for the
validation should be one that contains a wider area of the Interconnection than the Planning
Coordinator’s area. If the simulations can be made to match the actual system responses by
reasonable changes to the data in the Planning Coordinator’s area, then the Planning
Coordinator should make those changes in coordination with the data provider. However, for
some disturbances, the data in the Planning Coordinator’s area may not be what is causing the
simulations to not match actual responses. These situations should be reported to the Electric
Reliability Organization (ERO). The guidelines the Planning Coordinator includes under Part 1.4
could cover these situations.
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:
In FERC Order No. 693, paragraph 1210, the Commission directed inclusion of “a requirement
that the models be validated against actual system responses.” Furthermore, the Commission
directs in paragraph 1211, “that actual system events be simulated and if the model output is
not within the accuracy required, the model shall be modified to achieve the necessary
accuracy.” Paragraph 1220 similarly directs validation against actual system responses relative
to dynamics system models. In FERC Order 890, paragraph 290, the Commission states that
“the models should be updated and benchmarked to actual events.” Requirement R1 addresses
these directives.
Requirement R1 requires the Planning Coordinator to implement a documented data validation
process to validate data in the Planning Coordinator’s portion of the existing system in the
steady-state and dynamic models to compare performance against expected behavior or
response, which is consistent with the Commission directives. The validation of the full
Interconnection-wide cases is left up to the Electric Reliability Organization (ERO) or its
designees, and is not addressed by this standard. The following items were chosen for the
validation requirement:
A. Comparison of performance of the existing system in a planning power flow model to actual
system behavior; and
B. Comparison of the performance of the existing system in a planning dynamics model to
actual system response.
Implementation of these validations will result in more accurate power flow and dynamic
models. This, in turn, should result in better correlation between system flows and voltages
Page 9 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

seen in power flow studies and the actual values seen by system operators during outage
conditions. Similar improvements should be expected for dynamics studies, such that the
results will more closely match the actual responses of the power system to disturbances.
Validation of model data is a good utility practice, but it does not easily lend itself to Reliability
Standards requirement language. Furthermore, it is challenging to determine specifications for
thresholds of disturbances that should be validated and how they are determined. Therefore,
this requirement focuses on the Planning Coordinator performing validation pursuant to its
process, which must include the attributes listed in parts 1.1 through 1.4, without specifying the
details of “how” it must validate, which is necessarily dependent upon facts and circumstances.
Other validations are best left to guidance rather than standard requirements.
Rationale for R2:
The Planning Coordinator will need actual system behavior data in order to perform the
validations required in R1. The Reliability Coordinator or Transmission Operator may have this
data. Requirement R2 requires the Reliability Coordinator and Transmission Operator to supply
actual system data, if it has the data, to any requesting Planning Coordinator for purposes of
model validation under Requirement R1.
This could also include information the Reliability Coordinator or Transmission Operator has at
a field site. For example, if a PMU or DFR is at a generator site and it is recording the
disturbance, the Reliability Coordinator or Transmission Operator would typically have that
data.

Version History
Version

Date

Action

1

February 6,
2014

Adopted by the NERC Board of
Trustees.

1

May 1, 2014

FERC Order issued approving
MOD-033-1.

2

February 6,
2020

Adopted by the NERC Board of
Trustees.

Change Tracking

Developed as a new
standard for system
validation to address
outstanding directives
from FERC Order No. 693
and recommendations
from several other
sources.

Revisions under Project
2017-07

Page 10 of 10

Exhibit A-4
Proposed Reliability Standard MOD-033-2
Redline to Last Approved (MOD-033-1)

RELIABILITY | RESILIENCE | SECURITY

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

A. Introduction
1.

Title: Steady-State and Dynamic System Model Validation

2.

Number:

3.

Purpose:
To establish consistent validation requirements to facilitate the
collection of accurate data and building of planning models to analyze the reliability of
the interconnected transmission system.

4.

Applicability:

MOD-033-21

4.1. Functional Entities:
4.1.1 Planning Authority and Planning Coordinator (hereafter referred to as
“Planning Coordinator”)
4.1.24.1.1
This proposed standard combines “Planning Authority” with
“Planning Coordinator” in the list of applicable functional entities. The
NERC Functional Model lists “Planning Coordinator” while the
registration criteria list “Planning Authority,” and they are not yet
synchronized. Until that occurs, the proposed standard applies to both
Planning Authority and Planning Coordinator.

5.

4.1.34.1.2

Reliability Coordinator

4.1.44.1.3

Transmission Operator

Effective Date:
MOD-033-1 shall become effective on the first day of the first calendar quarter that is
36 months 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 that is 36
months after the date the standard is adopted by the NERC Board of Trustees or as
otherwise provided for in that jurisdiction.See Implementation Plan.

6.

Background:
MOD-033-1 exists in conjunction with MOD-032-1, both of which are related to
system-level modeling and validation. Reliability Standard MOD-032-1 is a
consolidation and replacement of existing MOD-010-0, MOD-011-0, MOD-012-0,
MOD-013-1, MOD-014-0, and MOD-015-0.1, and it requires data submission by
applicable data owners to their respective Transmission Planners and Planning
Coordinators to support the Interconnection-wide case building process in their
Interconnection. Reliability Standard MOD-033-1 is a new standard, and it requires
each Planning Coordinator to implement a documented process to perform model
validation within its planning area.

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

The transition and focus of responsibility upon the Planning Coordinator function in
both standards are driven by several recommendations and FERC directives (to
include several remaining directives from FERC Order No. 693), which are discussed in
greater detail in the rationale sections of the standards. One of the most recent and
significant set of recommendations came from the NERC Planning Committee’s
System Analysis and Modeling Subcommittee (SAMS). SAMS proposed several
improvements to the modeling data standards, to include consolidation of the
standards (that whitepaper is available from the December 2012 NERC Planning
Committee’s agenda package, item 3.4, beginning on page 99, here:
http://www.nerc.com/comm/PC/Agendas%20Highlights%20and%20Minutes%20DL/2
012/2012_Dec_PC%20Agenda.pdf).
The focus of validation in this standard is not Interconnection-wide phenomena, but
on the Planning Coordinator’s portion of the existing system. The Reliability Standard
requires Planning Coordinators to implement a documented data validation process
for power flow and dynamics. For the dynamics validation, the target of validation is
those events that the Planning Coordinator determines are dynamic local events. A
dynamic local event could include such things as closing a transmission line near a
generating plant. A dynamic local event is a disturbance on the power system that
produces some measurable transient response, such as oscillations. It could involve
one small area of the system or a generating plant oscillating against the rest of the
grid. The rest of the grid should not have a significant effect. Oscillations involving
large areas of the grid are not local events. However, a dynamic local event could also
be a subset of a larger disturbance involving large areas of the grid.
B. Requirements and Measures
R1.

Each Planning Coordinator shall implement a documented data validation process
that includes the following attributes: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
1.1. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning power flow model to actual system behavior,
represented by a state estimator case or other Real-time data sources, at least
once every 24 calendar months through simulation;
1.2. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning dynamic model to actual system response, through
simulation of a dynamic local event, at least once every 24 calendar months (use
a dynamic local event that occurs within 24 calendar months of the last dynamic
local event used in comparison, and complete each comparison within 24
calendar months of the dynamic local event). If no dynamic local event occurs
within the 24 calendar months, use the next dynamic local event that occurs;
1.3. Guidelines the Planning Coordinator will use to determine unacceptable
differences in performance under Part 1.1 or 1.2; and

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

1.4. Guidelines to resolve the unacceptable differences in performance identified
under Part 1.3.
M1. Each Planning Coordinator shall provide evidence that it has a documented validation

process according to Requirement R1 as well as evidence that demonstrates the
implementation of the required components of the process.

R2.

Each Reliability Coordinator and Transmission Operator shall provide actual system
behavior data (or a written response that it does not have the requested data) to any
Planning Coordinator performing validation under Requirement R1 within 30 calendar
days of a written request, such as, but not limited to, state estimator case or other
Real-time data (including disturbance data recordings) necessary for actual system
response validation. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

M2. Each Reliability Coordinator and Transmission Operator shall provide evidence, such

as email notices or postal receipts showing recipient and date that it has distributed
the requested data or written response that it does not have the data, to any Planning
Coordinator performing validation under Requirement R1 within 30 days of a written
request in accordance with Requirement R2; or a statement by the Reliability
Coordinator or Transmission Operator that it has not received notification regarding
data necessary for validation by any Planning Coordinator.

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity in their
respective roles of monitoring and enforcing compliance with the NERC
Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance with
Requirements R1 through R2, and Measures M1 through M2, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an applicable entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Refer to Section 3.0 of Appendix 4C of the NERC Rules of Procedure for a list of
compliance monitoring and assessment processes.
1.4. Additional Compliance Information
None

MOD-033-2 — Steady-State and Dynamic System Model Validation

Table of Compliance Elements
R#

Time Horizon

Violation Severity Levels

VRF
Lower VSL

R1

Long-term
Planning

Medium The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address one of the
four required topics
under Requirement
R1;

Moderate VSL

High VSL

Severe VSL

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address two of the
four required topics
under Requirement
R1;

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address three of the
four required topics
under Requirement
R1;

The Planning
Coordinator did not
have a validation
process at all or did
not document or
implement any of the
four required topics
under Requirement
R1;

OR

OR

OR

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation within 28
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months;

The Planning
Coordinator did not
validate its portion of
the system in the
power flow model as
required by part 1.1
within 36 calendar
months;

OR

OR

OR
The Planning
Coordinator did not
perform simulation as

OR

OR
The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 36 calendar

Page 5 of 12

MOD-033-2 — Steady-State and Dynamic System Model Validation

R2

Long-term
Planning

Lower

required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation within 28
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months.

months (or the next
dynamic local event in
cases where there is
more than 24 months
between events).

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 30
calendar days of the
written request, but

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 30
calendar days of the
written request, but

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 30
calendar days of the
written request, but

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 75
calendar days;

Page 6 of 12

MOD-033-2 — Steady-State and Dynamic System Model Validation

did provide the data
(or written response
that it does not have
the requested data) in
less than or equal to
45 calendar days.

did provide the data
(or written response
that it does not have
the requested data) in
greater than 45
calendar days but less
than or equal to 60
calendar days.

did provide the data
(or written response
that it does not have
the requested data) in
greater than 60
calendar days but less
than or equal to 75
calendar days.

OR
The Reliability
Coordinator or
Transmission Operator
provided a written
response that it does
not have the
requested data, but
actually had the data.

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Page 7 of 12

MOD-033-2 — Steady-State and Dynamic System Model ValidationApplication Guidelines

Guidelines and Technical Basis
Requirement R1:
The requirement focuses on the results-based outcome of developing a process for and
performing a validation, but does not prescribe a specific method or procedure for the
validation outside of the attributes specified in the requirement. For further information on
suggested validation procedures, see “Procedures for Validation of Powerflow and Dynamics
Cases” produced by the NERC Model Working Group.
The specific process is left to the judgment of the Planning Coordinator, but the Planning
Coordinator is required to develop and include in its process guidelines for evaluating
discrepancies between actual system behavior or response and expected system performance
for determining whether the discrepancies are unacceptable.
For the validation in part 1.1, the state estimator case or other Real-time data should be taken
as close to system peak as possible. However, other snapshots of the system could be used if
deemed to be more appropriate by the Planning Coordinator. While the requirement specifies
“once every 24 calendar months,” entities are encouraged to perform the comparison on a
more frequent basis.
In performing the comparison required in part 1.1, the Planning Coordinator may consider,
among other criteria:
1. System load;
2. Transmission topology and parameters;
3. Voltage at major buses; and
4. Flows on major transmission elements.
The validation in part 1.1 would include consideration of the load distribution and load power
factors (as applicable) used in the power flow models. The validation may be made using
metered load data if state estimator cases are not available. The comparison of system load
distribution and load power factors shall be made on an aggregate company or power flow
zone level at a minimum but may also be made on a bus by bus, load pocket (e.g., within a
Balancing Authority), or smaller area basis as deemed appropriate by the Planning Coordinator.
The scope of dynamics model validation is intended to be limited, for purposes of part 1.2, to
the Planning Coordinator’s planning area, and the intended emphasis under the requirement is
on local events or local phenomena, not the whole Interconnection.
The validation required in part 1.2 may include simulations that are to be compared with actual
system data and may include comparisons of:
•

Voltage oscillations at major buses

•

System frequency (for events with frequency excursions)

•

Real and reactive power oscillations on generating units and major inter-area ties

MOD-033-2 — Steady-State and Dynamic System Model ValidationApplication Guidelines

Determining when a dynamic local event might occur may be unpredictable, and because of the
analytic complexities involved in simulation, the time parameters in part 1.2 specify that the
comparison period of “at least once every 24 calendar months” is intended to both provide for
at least 24 months between dynamic local events used in the comparisons and that
comparisons must be completed within 24 months of the date of the dynamic local event used.
This clarification ensures that PCs will not face a timing scenario that makes it impossible to
comply. If the time referred to the completion time of the comparison, it would be possible for
an event to occur in month 23 since the last comparison, leaving only one month to complete
the comparison. With the 30 day timeframe in Requirement R2 for TOPs or RCs to provide
actual system behavior data (if necessary in the comparison), it would potentially be impossible
to complete the comparison within the 24 month timeframe.
In contrast, the requirement language clarifies that the time frame between dynamic local
events used in the comparisons should be within 24 months of each other (or, as specified at
the end of part 1.2, in the event more than 24 months passes before the next dynamic local
event, the comparison should use the next dynamic local event that occurs). Each comparison
must be completed within 24 months of the dynamic local event used. In this manner, the
potential problem with a “month 23” dynamic local event described above is resolved. For
example, if a PC uses for comparison a dynamic local event occurring on day 1 of month 1, the
PC has 24 calendar months from that dynamic local event’s occurrence to complete the
comparison. If the next dynamic event the PC chooses for comparison occurs in month 23, the
PC has 24 months from that dynamic local event’s occurrence to complete the comparison.
Part 1.3 requires the PC to include guidelines in its documented validation process for
determining when discrepancies in the comparison of simulation results with actual system
results are unacceptable. The PC may develop the guidelines required by parts 1.3 and 1.4
itself, reference other established guidelines, or both. For the power flow comparison, as an
example, this could include a guideline the Planning Coordinator will use that flows on 500 kV
lines should be within 10% or 100 MW, whichever is larger. It could be different percentages or
MW amounts for different voltage levels. Or, as another example, the guideline for voltage
comparisons could be that it must be within 1%. But the guidelines the PC includes within its
documented validation process should be meaningful for the Planning Coordinator’s system.
Guidelines for the dynamic event comparison may be less precise. Regardless, the comparison
should indicate that the conclusions drawn from the two results should be consistent. For
example, the guideline could state that the simulation result will be plotted on the same graph
as the actual system response. Then the two plots could be given a visual inspection to see if
they look similar or not. Or a guideline could be defined such that the rise time of the transient
response in the simulation should be within 20% of the rise time of the actual system response.
As for the power flow guidelines, the dynamic comparison criteria should be meaningful for the
Planning Coordinator’s system.
The guidelines the PC includes in its documented validation process to resolve differences in
Part 1.4 could include direct coordination with the data owner, and, if necessary, through the
provisions of MOD-032-1, Requirement R3 (i.e., the validation performed under this
requirement could identify technical concerns with the data). In other words, while this
standard is focused on validation, results of the validation may identify data provided under the

MOD-033-2 — Steady-State and Dynamic System Model ValidationApplication Guidelines

modeling data standard that needs to be corrected. If a model with estimated data or a generic
model is used for a generator, and the model response does not match the actual response,
then the estimated data should be corrected or a more detailed model should be requested
from the data provider.
While the validation is focused on the Planning Coordinator’s planning area, the model for the
validation should be one that contains a wider area of the Interconnection than the Planning
Coordinator’s area. If the simulations can be made to match the actual system responses by
reasonable changes to the data in the Planning Coordinator’s area, then the Planning
Coordinator should make those changes in coordination with the data provider. However, for
some disturbances, the data in the Planning Coordinator’s area may not be what is causing the
simulations to not match actual responses. These situations should be reported to the Electric
Reliability Organization (ERO). The guidelines the Planning Coordinator includes under Part 1.4
could cover these situations.
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:
In FERC Order No. 693, paragraph 1210, the Commission directed inclusion of “a requirement
that the models be validated against actual system responses.” Furthermore, the Commission
directs in paragraph 1211, “that actual system events be simulated and if the model output is
not within the accuracy required, the model shall be modified to achieve the necessary
accuracy.” Paragraph 1220 similarly directs validation against actual system responses relative
to dynamics system models. In FERC Order 890, paragraph 290, the Commission states that
“the models should be updated and benchmarked to actual events.” Requirement R1 addresses
these directives.
Requirement R1 requires the Planning Coordinator to implement a documented data validation
process to validate data in the Planning Coordinator’s portion of the existing system in the
steady-state and dynamic models to compare performance against expected behavior or
response, which is consistent with the Commission directives. The validation of the full
Interconnection-wide cases is left up to the Electric Reliability Organization (ERO) or its
designees, and is not addressed by this standard. The following items were chosen for the
validation requirement:
A. Comparison of performance of the existing system in a planning power flow model to actual
system behavior; and
B. Comparison of the performance of the existing system in a planning dynamics model to
actual system response.

MOD-033-2 — Steady-State and Dynamic System Model ValidationApplication Guidelines

Implementation of these validations will result in more accurate power flow and dynamic
models. This, in turn, should result in better correlation between system flows and voltages
seen in power flow studies and the actual values seen by system operators during outage
conditions. Similar improvements should be expected for dynamics studies, such that the
results will more closely match the actual responses of the power system to disturbances.
Validation of model data is a good utility practice, but it does not easily lend itself to Reliability
Standards requirement language. Furthermore, it is challenging to determine specifications for
thresholds of disturbances that should be validated and how they are determined. Therefore,
this requirement focuses on the Planning Coordinator performing validation pursuant to its
process, which must include the attributes listed in parts 1.1 through 1.4, without specifying the
details of “how” it must validate, which is necessarily dependent upon facts and circumstances.
Other validations are best left to guidance rather than standard requirements.
Rationale for R2:
The Planning Coordinator will need actual system behavior data in order to perform the
validations required in R1. The Reliability Coordinator or Transmission Operator may have this
data. Requirement R2 requires the Reliability Coordinator and Transmission Operator to supply
actual system data, if it has the data, to any requesting Planning Coordinator for purposes of
model validation under Requirement R1.
This could also include information the Reliability Coordinator or Transmission Operator has at
a field site. For example, if a PMU or DFR is at a generator site and it is recording the
disturbance, the Reliability Coordinator or Transmission Operator would typically have that
data.

Version History
Version

Date

Action

1

February 6,
2014

Adopted by the NERC Board of
Trustees.

1

May 1, 2014

FERC Order issued approving
MOD-033-1.

Change Tracking
Developed as a new
standard for system
validation to address
outstanding directives
from FERC Order No. 693
and recommendations
from several other
sources.

MOD-033-2 — Steady-State and Dynamic System Model ValidationApplication Guidelines

2

February 6,
2020

Adopted by NERC Board of
Trustees.

Revisions under Project
2017-07

Exhibit A-5
Proposed Reliability Standard NUC-001-4
Clean

RELIABILITY | RESILIENCE | SECURITY

NUC-001-4— Nuclear Plant Interface Coordination

A. Introduction
1.

Title:

Nuclear Plant Interface Coordination

2.

Number:

NUC-001-4

3.

Purpose: This standard requires coordination between Nuclear Plant Generator
Operators and Transmission Entities for the purpose of ensuring nuclear plant safe
operation and shutdown.

4.

Applicability:
4.1. Functional Entities:
4.1.1 Nuclear Plant Generator Operators.
4.2. Transmission Entities shall mean all entities that are responsible for providing
services related to Nuclear Plant Interface Requirements (NPIRs). Such entities
may include one or more of the following:
4.2.1 Transmission Operators.
4.2.2 Transmission Owners.
4.2.3 Transmission Planners.
4.2.4 Transmission Service Providers.
4.2.5 Balancing Authorities.
4.2.6 Reliability Coordinators.
4.2.7 Planning Coordinators.
4.2.8 Distribution Providers.
4.2.9 Generator Owners.
4.2.10 Generator Operators.

5.

Effective Date: See Implementation Plan.

Page 1 of 16

NUC-001-4— Nuclear Plant Interface Coordination

B. Requirements and Measures
R1.

The Nuclear Plant Generator Operator shall provide the proposed NPIRs in writing to
the applicable Transmission Entities and shall verify receipt. [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning ]

M1. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, provide a copy of the transmittal and receipt of transmittal of
the proposed NPIRs to the responsible Transmission Entities.
R2.

The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
have in effect one or more Agreements 1 that include mutually agreed to NPIRs and
document how the Nuclear Plant Generator Operator and the applicable Transmission
Entities shall address and implement these NPIRs. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning ]

M2. The Nuclear Plant Generator Operator and each Transmission Entity shall each have a
copy of the currently effective Agreement(s) which document how the Nuclear Plant
Generator Operator and the applicable Transmission Entities address and implement
the NPIRs available for inspection upon request of the Compliance Enforcement
Authority.
R3.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall incorporate the NPIRs into their planning analyses of the
electric system and shall communicate the results of these analyses to the Nuclear
Plant Generator Operator.: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]

M3. Each Transmission Entity responsible for planning analyses in accordance with the
Agreement shall, upon request of the Compliance Enforcement Authority, provide a
copy of the planning analyses results transmitted to the Nuclear Plant Generator
Operator, showing incorporation of the NPIRs. The Compliance Enforcement
Authority shall refer to the Agreements developed in accordance with this standard
for specific requirements.
R4.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall [Violation Risk Factor: High] [Time Horizon: Operations
Planning and Real-time Operations]
4.1. Incorporate the NPIRs into their operating analyses of the electric system.
4.2. Operate the electric system to meet the NPIRs.

Agreements may include mutually agreed upon procedures or protocols in effect between entities or between departments of
a vertically integrated system.

1

Page 2 of 16

NUC-001-4— Nuclear Plant Interface Coordination

4.3. Inform the Nuclear Plant Generator Operator when the ability to assess the
operation of the electric system affecting NPIRs is lost.
M4. Each Transmission Entity responsible for operating the electric system in accordance
with the Agreement shall demonstrate or provide evidence of the following, upon
request of the Compliance Enforcement Authority:

R5.

•

The NPIRs have been incorporated into the current operating analysis of the
electric system. (Requirement 4.1)

•

The electric system was operated to meet the NPIRs. (Requirement 4.2)

•

The Transmission Entity informed the Nuclear Plant Generator Operator when it
became aware it lost the capability to assess the operation of the electric system
affecting the NPIRs

Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall operate the nuclear plant to meet the NPIRs. [Violation Risk
Factor: High] [Time Horizon: Operations Planning and Real-time Operations ]

M5. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, demonstrate or provide evidence that the nuclear power
plant is being operated consistent with the NPIRs.
R6.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities and the Nuclear Plant Generator Operator shall coordinate
outages and maintenance activities which affect the NPIRs. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]

M6. The Transmission Entities and Nuclear Plant Generator Operator shall, upon request
of the Compliance Enforcement Authority, provide evidence of the coordination
between the Transmission Entities and the Nuclear Plant Generator Operator
regarding outages and maintenance activities which affect the NPIRs.
R7.

Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall inform the applicable Transmission Entities of actual or
proposed changes to nuclear plant design (e.g., protective relay setpoints),
configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]

M7. The Nuclear Plant Generator Operator shall provide evidence that it informed the
applicable Transmission Entities of changes to nuclear plant design (e.g., protective
relay setpoints), configuration, operations, limits, or capabilities that may impact the
ability of the Transmission Entities to meet the NPIRs.

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NUC-001-4— Nuclear Plant Interface Coordination

R8.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall inform the Nuclear Plant Generator Operator of actual or
proposed changes to electric system design (e.g., protective relay setpoints),
configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]

M8. The Transmission Entities shall each provide evidence that the entities informed the
Nuclear Plant Generator Operator of changes to electric system design (e.g.,
protective relay setpoints), configuration, operations, limits, or capabilities that may
impact the ability of the Nuclear Plant Generator Operator to meet the NPIRs.
R9.

The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
include the following elements in aggregate within the Agreement(s) identified in R2.
•

Where multiple Agreements with a single Transmission Entity are put into effect,
the R9 elements must be addressed in aggregate within the Agreements;
however, each Agreement does not have to contain each element. The Nuclear
Plant Generator Operator and the Transmission Entity are responsible for ensuring
all the R9 elements are addressed in aggregate within the Agreements.

•

Where Agreements with multiple Transmission Entities are required, the Nuclear
Plant Generator Operator is responsible for ensuring all the R9 elements are
addressed in aggregate within the Agreements with the Transmission Entities. The
Agreements with each Transmission Entity do not have to contain each element;
however, the Agreements with the multiple Transmission Entities, in the
aggregate, must address all R9 elements. For each Agreement(s), the Nuclear
Plant Generator Operator and the Transmission Entity are responsible to ensure
the Agreement(s) contain(s) the elements of R9 applicable to that Transmission
Entity. : [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

9.1. Retired. [Note: Part 9.1 was retired under the Paragraph 81 project. The NUC SDT
proposes to leave this Part blank to avoid renumbering Requirement parts that
would impact existing agreements throughout the industry.]
9.2. Technical requirements and analysis:
9.2.1. Identification of parameters, limits, configurations, and operating
scenarios included in the NPIRs and, as applicable, procedures for
providing any specific data not provided within the Agreement.
9.2.2. Identification of facilities, components, and configuration restrictions that
are essential for meeting the NPIRs.
9.2.3. Types of planning and operational analyses performed specifically to
support the NPIRs, including the frequency of studies and types of
Contingencies and scenarios required.

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NUC-001-4— Nuclear Plant Interface Coordination

9.3. Operations and maintenance coordination
9.3.1. Designation of ownership of electrical facilities at the interface between
the electric system and the nuclear plant and responsibilities for
operational control coordination and maintenance of these facilities.
9.3.2. Identification of any maintenance requirements for equipment not
owned or controlled by the Nuclear Plant Generator Operator that are
necessary to meet the NPIRs.
9.3.3. Coordination of testing, calibration and maintenance of on-site and offsite power supply systems and related components.
9.3.4. Provisions to address mitigating actions needed to avoid violating NPIRs
and to address periods when responsible Transmission Entity loses the
ability to assess the capability of the electric system to meet the NPIRs.
These provisions shall include responsibility to notify the Nuclear Plant
Generator Operator within a specified time frame.
9.3.5. Provision for considering, within the restoration process, the
requirements and urgency of a nuclear plant that has lost all off-site and
on-site AC power.
9.3.6. Coordination of physical and cyber security protection at the nuclear
plant interface to ensure each asset is covered under at least one entity’s
plan.
9.3.7. Coordination of the NPIRs with transmission system Remedial Action
Schemes and any programs that reduce or shed load based on
underfrequency or undervoltage.
9.4. Communications and training Administrative elements:
9.4.1. Provisions for communications affecting the NPIRs between the Nuclear
Plant Generator Operator and Transmission Entities, including
communications protocols, notification time requirements, and
definitions of applicable unique terms.
9.4.2. Provisions for coordination during an off-normal or emergency event
affecting the NPIRs, including the need to provide timely information
explaining the event, an estimate of when the system will be returned to
a normal state, and the actual time the system is returned to normal.
9.4.3. Provisions for coordinating investigations of causes of unplanned events
affecting the NPIRs and developing solutions to minimize future risk of
such events.
9.4.4. Provisions for supplying information necessary to report to government
agencies, as related to NPIRs.
9.4.5. Provisions for personnel training, as related to NPIRs.

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NUC-001-4— Nuclear Plant Interface Coordination

M9. The Nuclear Plant Generator Operator shall have a copy of the Agreement(s)
addressing the elements in Requirement 9 available for inspection upon request of the
Compliance Enforcement Authority. Each Transmission Entity shall have a copy of the
Agreement(s) addressing the elements in Requirement 9 for which it is responsible available
for inspection upon request of the Compliance Enforcement Authority.

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NUC-001-4— Nuclear Plant Interface Coordination

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints Text
1.3. Data Retention
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
•

For Measure 1, the Nuclear Plant Generator Operator shall keep its latest
transmittals and receipts.

•

For Measure 2, the Nuclear Plant Generator Operator and each
Transmission Entity shall have its current, in-force Agreement.

•

For Measure 3, the Transmission Entity shall have the latest planning
analysis results.

•

For Measures 4, 6 and 8, the Transmission Entity shall keep evidence for
two years plus current.

•

For Measures 5, 6 and 7, the Nuclear Plant Generator Operator shall keep
evidence for two years plus current.

If a Responsible Entity is found non-compliant it shall keep information related to
the noncompliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None

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NUC-001-4— Nuclear Plant Interface Coordination

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

R1

R2

Medium The Nuclear Plant
Generator Operator
provided the NPIRs to
the applicable entities
but did not verify
receipt.

Medium N/A

Moderate VSL

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIR to one
of the applicable
entities unless there
was only one entity.

N/A

High VSL

Severe VSL

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIRs to
two of the applicable
entities unless there
were only two
entities.

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIRs to
more than two of
applicable entities.

N/A

The Nuclear Plant
Generator Operator or
the applicable
Transmission Entity
does not have in effect
one or more
agreements that
include mutually
agreed to NPIRs and

OR
For a particular
nuclear power plant, if
the number of
possible applicable
transmission entities is
equal to the number
of applicable
transmission entities
not provided NPIRs

Page 8 of 16

NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

document the
implementation of the
NPIRs.
R3

Medium N/A

The responsible entity
incorporated the
NPIRs into its planning
analyses but did not
communicate the
results to the Nuclear
Plant Generator
Operator.

N/A

The responsible entity
did not incorporate
the NPIRs into its
planning analyses of
the electric system.

R4

High

N/A

The responsible entity
did not comply with
Requirement R4, Part
4.3.

The responsible entity
did not comply with
Requirement R4, Part
R4.1.

The responsible entity
did not comply with
Requirement R4, Part
R4.2.

R5

High

N/A

N/A

N/A

The Nuclear Plant
Generator Operator
failed to operate per
the NPIRs developed
in accordance with
this standard.

R6

Medium N/A

The Nuclear Plant
Generator Operator or
Transmission Entity
failed to provide

The Nuclear Plant
N/A
Generator Operator or
Transmission Entity
failed to coordinate

Page 9 of 16

NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

outage or
maintenance
schedules to the
appropriate parties as
described in the
agreement or on a
time period consistent
with the agreements.

High VSL

Severe VSL

one or more outages
or maintenance
activities in
accordance the
requirements of the
agreements.

R7

High

The Nuclear Plant
N/A
Generator Operator
did not inform the
applicable
Transmission Entities
of proposed changes
to nuclear plant design
(e.g. protective relay
setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

The Nuclear Plant
Generator Operator
did not inform the
applicable
Transmission Entities
of actual changes to
nuclear plant design
(e.g. protective relay
setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

The Nuclear Plant
Generator Operator
did not inform the
applicable
Transmission Entities
of actual changes to
nuclear plant design
(e.g., protective relay
setpoints),
configuration,
operations, limits or
capabilities that
directly impact the
ability of the electric
system to meet the
NPIRs.

R8

High

The applicable
Transmission Entities
did not inform the

The applicable
Transmission Entities
did not inform the

The applicable
Transmission Entities
did not inform the

N/A

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

Nuclear Plant
Generator Operator of
proposed changes to
transmission system
design, configuration
(e.g. protective relay
setpoints), operations,
limits, or capabilities
that may impact the
ability of the electric
system to meet the
NPIRs.
R9

Medium

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include up to
20% of the combined
sub-components in
Requirement R9 Parts
9.2, 9.3 and 9.4
applicable to that
entity.

High VSL

Severe VSL

Nuclear Plant
Generator Operator of
actual changes to
transmission system
design (e.g. protective
relay setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

Nuclear Plant
Generator Operator of
actual changes to
transmission system
design (e.g. protective
relay setpoints),
configuration,
operations, limits, or
capabilities that
directly impacts the
ability of the electric
system to meet the
NPIRs.

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include
greater than 20%, but
less than 40% of the
combined subcomponents in
Requirement R9 Parts
9.2, 9.3 and 9.4

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include 40%
or more of the
combined subcomponents in
Requirement R9 Parts
9.2, 9.3 and 9.4

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

applicable to the
entity.

Severe VSL

applicable to the
entity.

Page 12 of 16

NUC-001-4— Nuclear Plant Interface Coordination

D. Regional Variances
The design basis for Canadian (CANDU) nuclear power plants (NPPs) does not result in the
same licensing requirements as U.S. NPPs. Nuclear Regulatory Commission (NRC) design
criteria specifies that in addition to emergency on-site electrical power, electrical power
from the electric network also be provided to permit safe shutdown. There are no
equivalent Canadian Regulatory requirements for electrical power from the electric network
to be provided to permit safe shutdown. Therefore the definition of Nuclear Plant Licensing
Requirements (NPLR) for Canadian CANDU NPPs will be as follows:
Canadian Nuclear Plant Licensing Requirements (CNPLR) are requirements included in the
design basis of the nuclear plant and are statutorily mandated for the operation of the
plant; when used in this standard, NPLR shall mean nuclear power plant licensing
requirements for avoiding preventable challenges to nuclear safety as a result of an electric
system disturbance, transient, or condition.

E. Interpretations
None

F. Associated Documents
None

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NUC-001-4— Nuclear Plant Interface Coordination

Version History
Version

Date

Action

Change Tracking

1

May 2, 2007

Approved by Board of
Trustees

2

August 5, 2009

Adopted by Board of Trustees Revised. Modifications
for Order 716 to
Requirement R9.3.5 and
footnote 1;
modifications to bring
compliance elements
into conformance with
the latest version of the
ERO Rules of Procedure.

2

January 22, 2010

Approved by FERC on January
21, 2010. Added Effective
Date

2

February 7, 2013

R9.1, R9.1.1, R9.1.2, R9.1.3,
and R9.1.4 and associated
elements approved by NERC
Board of Trustees for
retirement as part of the
Paragraph 81 project (Project
2013-02) pending applicable
regulatory approval.

2

November 21, 2013 R9.1, R9.1.1, R9.1.2, R9.1.3,
and R9.1.4 and associated
elements approved by FERC
for retirement as part of the
Paragraph 81 project (Project
2013-02)

2.1

April 11, 2012

2.1

September 9, 2013

New

Update

Errata approved by the
Errata associated with
Standards Committee;
Project 2007-17
(Capitalized “Protection
System” in accordance with
Implementation Plan for
Project 2007-17 approval of
revised definition of
“Protection System”)
Informational filing submitted
to reflect the revised

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NUC-001-4— Nuclear Plant Interface Coordination

definition of Protection
System in accordance with
the Implementation Plan for
the revised term.
3

March 2014

Modifications to implement
the recommendations of the
five-year review of NUC-001,
which was accepted by the
Standards Committee on
October 17, 2013.

3

August 14, 2014

Adopted by the NERC Board
of Trustees

3

November 4, 2014

FERC letter order issued
approving NUC-001-3

4

February 6, 2020

Adopted by NERC Board of
Trustees

Revision

Revisions under Project
2017-07

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 R5:
The NUC FYRT recommended R5 be revised for consistency with R4 and to clarify that nuclear
plants must be operated to meet the Nuclear Plant Interface Requirements.
Rationale for R7 and R8:
The NUC FYRT recommended deleting “Protection Systems” in Requirements R7 and R8 since it
is a subset of the "nuclear plant design" and "electric system design" elements currently
contained in R7 and R8 respectively; and adding a parenthetical clause (e.g. protective
setpoints) to R7 following "nuclear plant design" and parenthetical clause (e.g. relay setpoints)
to R8 following "electric system design."
Rationale for R9:
The NUC FYRT recommended that R9 be revised to clarify that all agreements do not have to
discuss each of the elements in R9, but that the sum total of the agreements need to address
the elements. In addition, for clarity in Part 9.4.1, the NUC FYRT recommended that "affecting
the NPIRs" be inserted following "Provisions for communications" and "applicable unique" be
inserted following ""definitions of."

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NUC-001-4— Nuclear Plant Interface Coordination

Rationale for R9.3.7:
The term “Special Protection Systems” (SPS) was replaced with “Remedial Action Schemes”
(RAS) in order to align with other current NERC standards development work in Project 201005.2: Special Protection Systems. Project 2010-05.2 has proposed to replace SPS with RAS
throughout all of the NERC Standards in order to move to the use of a single term. RAS and SPS
have the same definition in the NERC Glossary of Terms.

Page 16 of 16

Exhibit A-5
Proposed Reliability Standard NUC-001-4
Redline to Last Approved (NUC-001-3)

RELIABILITY | RESILIENCE | SECURITY

NUC-001-34— Nuclear Plant Interface Coordination

A. Introduction
1.

Title:

Nuclear Plant Interface Coordination

2.

Number:

NUC-001-43

3.

Purpose: This standard requires coordination between Nuclear Plant Generator
Operators and Transmission Entities for the purpose of ensuring nuclear plant safe
operation and shutdown.

4.

Applicability:
4.1. Functional Entities:
4.1.1

Nuclear Plant Generator Operators.

4.2. Transmission Entities shall mean all entities that are responsible for providing
services related to Nuclear Plant Interface Requirements (NPIRs). Such entities
may include one or more of the following:
4.2.1

Transmission Operators.

4.2.2

Transmission Owners.

4.2.3

Transmission Planners.

4.2.4

Transmission Service Providers.

4.2.5

Balancing Authorities.

4.2.6

Reliability Coordinators.

4.2.7

Planning Coordinators.

4.2.8
4.2.8
4.2.9

Distribution Providers.
Formatted: Outline numbered + Level: 3 + Numbering
Style: 1, 2, 3, … + Start at: 1 + Alignment: Left + Aligned at:
1" + Tab after: 1.5" + Indent at: 1.5"

Load-Serving Entities.

4.2.104.2.9

Generator Owners.

4.2.114.2.10 Generator Operators.
5.

Effective Date: See Implementation Plan.

Background: Project 2012-13 Nuclear Power Interface Coordination seeks to implement
the changes that were proposed by the NUC FYRT. The NUC FYRT was appointed by the
Standards Committee Executive Committee on April 22, 2013. The NUC FYRT reviewed
the NUC-001-2.1 standard to identify opportunities for consolidation and additional
improvements. The NUC FYRT posted its recommendation to revise NUC-001-2.1 for
industry comment on July 27, 2013. The NUC FYRT considered comments and submitted its
final recommendation to revise NUC-001-2.1, along with a Standards Authorization Request
(SAR) to the Standards Committee on October 17, 2013. The Standards Committee accepted

Page 1 of 13

NUC-001-34— Nuclear Plant Interface Coordination

the recommendation of the FYRT and appointed the team as the Standard Drafting Team
(SDT) to implement the recommendation.
5.

Effective Dates: First day of the first calendar quarter that is twelve months beyond
the date that this standard is approved by applicable regulatory authorities, 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 that is twelve months after the date this standard is
adopted by the NERC Board of Trustees or as otherwise provided for in that
jurisdiction.

B. Requirements and Measures
R1. The Nuclear Plant Generator Operator shall provide the proposed NPIRs in writing to
the applicable Transmission Entities and shall verify receipt. [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning ]
M1. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, provide a copy of the transmittal and receipt of transmittal of
the proposed NPIRs to the responsible Transmission Entities.
R2. The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
have in effect one or more Agreements 1 that include mutually agreed to NPIRs and
document how the Nuclear Plant Generator Operator and the applicable Transmission
Entities shall address and implement these NPIRs. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning ]
M2. The Nuclear Plant Generator Operator and each Transmission Entity shall each have a
copy of the currently effective Agreement(s) which document how the Nuclear Plant
Generator Operator and the applicable Transmission Entities address and implement
the NPIRs available for inspection upon request of the Compliance Enforcement
Authority.
R3. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall incorporate the NPIRs into their planning analyses of the
electric system and shall communicate the results of these analyses to the Nuclear Plant
Generator Operator.: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning ]
M3. Each Transmission Entity responsible for planning analyses in accordance with the
Agreement shall, upon request of the Compliance Enforcement Authority, provide a
copy of the planning analyses results transmitted to the Nuclear Plant Generator
Operator, showing incorporation of the NPIRs. The Compliance Enforcement
1

Agreements may include mutually agreed upon procedures or protocols in effect between entities or between
departments of a vertically integrated system.

Page 2 of 13

NUC-001-34— Nuclear Plant Interface Coordination

Authority shall refer to the Agreements developed in accordance with this standard for
specific requirements.
R4. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall [Violation Risk Factor: High] [Time Horizon: Operations
Planning and Real-time Operations]
4.1. Incorporate the NPIRs into their operating analyses of the electric system.
4.2. Operate the electric system to meet the NPIRs.
4.3. Inform the Nuclear Plant Generator Operator when the ability to assess the
operation of the electric system affecting NPIRs is lost.
M4. Each Transmission Entity responsible for operating the electric system in accordance
with the Agreement shall demonstrate or provide evidence of the following, upon
request of the Compliance Enforcement Authority:
•

The NPIRs have been incorporated into the current operating analysis of the
electric system. (Requirement 4.1)

•

The electric system was operated to meet the NPIRs. (Requirement 4.2)

•

The Transmission Entity informed the Nuclear Plant Generator Operator when
it became aware it lost the capability to assess the operation of the electric
system affecting the NPIRs

R5. Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall operate the nuclear plant to meet the NPIRs. [Violation Risk
Factor: High] [Time Horizon: Operations Planning and Real-time Operations ]
M5. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, demonstrate or provide evidence that the nuclear power plant
is being operated consistent with the NPIRs.
R6. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities and the Nuclear Plant Generator Operator shall coordinate
outages and maintenance activities which affect the NPIRs. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]
M6. The Transmission Entities and Nuclear Plant Generator Operator shall, upon request of
the Compliance Enforcement Authority, provide evidence of the coordination between
the Transmission Entities and the Nuclear Plant Generator Operator regarding outages
and maintenance activities which affect the NPIRs.
R7. Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall inform the applicable Transmission Entities of actual or
proposed changes to nuclear plant design (e.g., protective relay setpoints),

Page 3 of 13

NUC-001-34— Nuclear Plant Interface Coordination

configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
M7. The Nuclear Plant Generator Operator shall provide evidence that it informed the
applicable Transmission Entities of changes to nuclear plant design (e.g., protective
relay setpoints), configuration, operations, limits, or capabilities that may impact the
ability of the Transmission Entities to meet the NPIRs.
R8. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall inform the Nuclear Plant Generator Operator of actual or
proposed changes to electric system design (e.g., protective relay setpoints),
configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
M8. The Transmission Entities shall each provide evidence that the entities informed the
Nuclear Plant Generator Operator of changes to electric system design (e.g., protective
relay setpoints), configuration, operations, limits, or capabilities that may impact the
ability of the Nuclear Plant Generator Operator to meet the NPIRs.
R9. The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
include the following elements in aggregate within the Agreement(s) identified in R2.
•

Where multiple Agreements with a single Transmission Entity are put into
effect, the R9 elements must be addressed in aggregate within the
Agreements; however, each Agreement does not have to contain each
element. The Nuclear Plant Generator Operator and the Transmission Entity
are responsible for ensuring all the R9 elements are addressed in aggregate
within the Agreements.

•

Where Agreements with multiple Transmission Entities are required, the
Nuclear Plant Generator Operator is responsible for ensuring all the R9
elements are addressed in aggregate within the Agreements with the
Transmission Entities. The Agreements with each Transmission Entity do not
have to contain each element; however, the Agreements with the multiple
Transmission Entities, in the aggregate, must address all R9 elements. For
each Agreement(s), the Nuclear Plant Generator Operator and the
Transmission Entity are responsible to ensure the Agreement(s) contain(s) the
elements of R9 applicable to that Transmission Entity. : [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]

9.1. Retired. [Note: Part 9.1 was retired under the Paragraph 81 project. The
NUC SDT proposes to leave this Part blank to avoid renumbering Requirement
parts that would impact existing agreements throughout the industry.]

Page 4 of 13

Formatted: Indent: Left: 1", No bullets or numbering

NUC-001-34— Nuclear Plant Interface Coordination

9.2.9.1.

Technical requirements and analysis:

9.2.1.9.1.1. Identification of parameters, limits, configurations, and operating
scenarios included in the NPIRs and, as applicable, procedures for
providing any specific data not provided within the Agreement.
9.2.2.9.1.2. Identification of facilities, components, and configuration
restrictions that are essential for meeting the NPIRs.
9.2.3.9.1.3. Types of planning and operational analyses performed specifically
to support the NPIRs, including the frequency of studies and types of
Contingencies and scenarios required.
9.3.9.2.

Operations and maintenance coordination

9.3.1.9.2.1. Designation of ownership of electrical facilities at the interface
between the electric system and the nuclear plant and responsibilities for
operational control coordination and maintenance of these facilities.
9.3.2.9.2.2. Identification of any maintenance requirements for equipment not
owned or controlled by the Nuclear Plant Generator Operator that are
necessary to meet the NPIRs.
9.3.3.9.2.3. Coordination of testing, calibration and maintenance of on-site and
off-site power supply systems and related components.
9.3.4.9.2.4. Provisions to address mitigating actions needed to avoid violating
NPIRs and to address periods when responsible Transmission Entity loses
the ability to assess the capability of the electric system to meet the
NPIRs. These provisions shall include responsibility to notify the Nuclear
Plant Generator Operator within a specified time frame.
9.3.5.9.2.5. Provision for considering, within the restoration process, the
requirements and urgency of a nuclear plant that has lost all off-site and
on-site AC power.
9.3.6.9.2.6. Coordination of physical and cyber security protection at the
nuclear plant interface to ensure each asset is covered under at least one
entity’s plan.
9.3.7.9.2.7. Coordination of the NPIRs with transmission system Remedial
Action Schemes and any programs that reduce or shed load based on
underfrequency or undervoltage.
9.4.9.3.

Communications and training Administrative elements:

9.4.1.9.3.1. Provisions for communications affecting the NPIRs between the
Nuclear Plant Generator Operator and Transmission Entities, including
communications protocols, notification time requirements, and definitions
of applicable unique terms.
9.4.2.9.3.2. Provisions for coordination during an off-normal or emergency
event affecting the NPIRs, including the need to provide timely
information explaining the event, an estimate of when the system will be

Page 5 of 13

NUC-001-34— Nuclear Plant Interface Coordination

returned to a normal state, and the actual time the system is returned to
normal.
9.4.3.9.3.3. Provisions for coordinating investigations of causes of unplanned
events affecting the NPIRs and developing solutions to minimize future
risk of such events.
9.4.4.9.3.4. Provisions for supplying information necessary to report to
government agencies, as related to NPIRs.
9.4.5.9.3.5.

Provisions for personnel training, as related to NPIRs.

M9. The Nuclear Plant Generator Operator shall have a copy of the Agreement(s) addressing
the elements in Requirement 9 available for inspection upon request of the Compliance
Enforcement Authority. Each Transmission Entity shall have a copy of the Agreement(s)
addressing the elements in Requirement 9 for which it is responsible available for inspection
upon request of the Compliance Enforcement Authority.

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints Text
1.3. Data Retention
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
•

For Measure 1, the Nuclear Plant Generator Operator shall keep its latest
transmittals and receipts.

•

For Measure 2, the Nuclear Plant Generator Operator and each
Transmission Entity shall have its current, in-force Agreement.

Page 6 of 13

NUC-001-34— Nuclear Plant Interface Coordination

•

For Measure 3, the Transmission Entity shall have the latest planning
analysis results.

•

For Measures 4, 6 and 8, the Transmission Entity shall keep evidence for
two years plus current.

•

For Measures 5, 6 and 7, the Nuclear Plant Generator Operator shall keep
evidence for two years plus current.

If a Responsible Entity is found non-compliant it shall keep information related to
the noncompliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None

Page 7 of 13

NUC-001-34— Nuclear Plant Interface Coordination

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

R1

Medium The Nuclear Plant
Generator Operator
provided the NPIRs to the
applicable entities but did
not verify receipt.

Moderate VSL

High VSL

Severe VSL

The Nuclear Plant
Generator Operator did not
provide the proposed NPIR
to one of the applicable
entities unless there was
only one entity.

The Nuclear Plant
Generator Operator did not
provide the proposed
NPIRs to two of the
applicable entities unless
there were only two
entities.

The Nuclear Plant
Generator Operator did not
provide the proposed
NPIRs to more than two of
applicable entities.
OR
For a particular nuclear
power plant, if the number
of possible applicable
transmission entities is
equal to the number of
applicable transmission
entities not provided NPIRs

R2

Medium N/A

N/A

N/A

The Nuclear Plant
Generator Operator or the
applicable Transmission
Entity does not have in
effect one or more
agreements that include
mutually agreed to NPIRs
and document the
implementation of the
NPIRs.

R3

Medium N/A

The responsible entity
incorporated the NPIRs
into its planning analyses
but did not communicate

N/A

The responsible entity did
not incorporate the NPIRs
into its planning analyses of
the electric system.

Page 8 of 13

NUC-001-34— Nuclear Plant Interface Coordination
the results to the Nuclear
Plant Generator Operator.

R4

High

N/A

The responsible entity did
not comply with
Requirement R4, Part 4.3.

The responsible entity did
not comply with
Requirement R4, Part R4.1.

The responsible entity did
not comply with
Requirement R4, Part R4.2.

R5

High

N/A

N/A

N/A

The Nuclear Plant
Generator Operator failed
to operate per the NPIRs
developed in accordance
with this standard.

R6

Medium N/A

The Nuclear Plant
Generator Operator or
Transmission Entity failed
to provide outage or
maintenance schedules to
the appropriate parties as
described in the agreement
or on a time period
consistent with the
agreements.

The Nuclear Plant
Generator Operator or
Transmission Entity failed
to coordinate one or more
outages or maintenance
activities in accordance the
requirements of the
agreements.

N/A

R7

High

The Nuclear Plant
Generator Operator did not
inform the applicable
Transmission Entities of
proposed changes to
nuclear plant design (e.g.
protective relay setpoints),
configuration, operations,
limits, or capabilities that
may impact the ability of
the electric system to meet
the NPIRs.

N/A

The Nuclear Plant
Generator Operator did not
inform the applicable
Transmission Entities of
actual changes to nuclear
plant design (e.g. protective
relay setpoints),
configuration, operations,
limits, or capabilities that
may impact the ability of
the electric system to meet
the NPIRs.

The Nuclear Plant
Generator Operator did not
inform the applicable
Transmission Entities of
actual changes to nuclear
plant design (e.g.,
protective relay setpoints),
configuration, operations,
limits or capabilities that
directly impact the ability
of the electric system to
meet the NPIRs.

R8

High

The applicable
Transmission Entities did
not inform the Nuclear

N/A

The applicable
Transmission Entities did
not inform the Nuclear

The applicable
Transmission Entities did
not inform the Nuclear

Page 9 of 13

NUC-001-34— Nuclear Plant Interface Coordination
Plant Generator Operator of
proposed changes to
transmission system design,
configuration (e.g.
protective relay setpoints),
operations, limits, or
capabilities that may
impact the ability of the
electric system to meet the
NPIRs.

R9

Medium

The Agreement(s)
identified in R2. between
the Nuclear Plant Generator
Operator and the applicable
Transmission Entity failed
to include up to 20% of the
combined sub-components
in Requirement R9 Parts
9.2, 9.3 and 9.4 applicable
to that entity.

Plant Generator Operator of
actual changes to
transmission system design
(e.g. protective relay
setpoints), configuration,
operations, limits, or
capabilities that may
impact the ability of the
electric system to meet the
NPIRs.

Plant Generator Operator of
actual changes to
transmission system design
(e.g. protective relay
setpoints), configuration,
operations, limits, or
capabilities that directly
impacts the ability of the
electric system to meet the
NPIRs.

The Agreement(s)
identified in R2. between
the Nuclear Plant Generator
Operator and the applicable
Transmission Entity failed
to include greater than
20%, but less than 40% of
the combined subcomponents in
Requirement R9 Parts 9.2,
9.3 and 9.4 applicable to
the entity.

The Agreement(s)
identified in R2. between
the Nuclear Plant Generator
Operator and the applicable
Transmission Entity failed
to include 40% or more of
the combined subcomponents in
Requirement R9 Parts 9.2,
9.3 and 9.4 applicable to
the entity.

Page 10 of 13

NUC-001-4— Nuclear Plant Interface Coordination

D. Regional Variances
The design basis for Canadian (CANDU) nuclear power plants (NPPs) does not result in the
same licensing requirements as U.S. NPPs. Nuclear Regulatory Commission (NRC) design
criteria specifies that in addition to emergency on-site electrical power, electrical power from
the electric network also be provided to permit safe shutdown. There are no equivalent
Canadian Regulatory requirements for electrical power from the electric network to be
provided to permit safe shutdown. Therefore the definition of Nuclear Plant Licensing
Requirements (NPLR) for Canadian CANDU NPPs will be as follows:
Canadian Nuclear Plant Licensing Requirements (CNPLR) are requirements included in the
design basis of the nuclear plant and are statutorily mandated for the operation of the plant;
when used in this standard, NPLR shall mean nuclear power plant licensing requirements for
avoiding preventable challenges to nuclear safety as a result of an electric system
disturbance, transient, or condition.
E. Interpretations
None.
F. Associated Documents
None

Version History

Page 11 of 13

NUC-001-4— Nuclear Plant Interface Coordination

Version

Date

Action

Change Tracking

1

May 2, 2007

Approved by Board of Trustees

New

2

August 5, 2009

Adopted by Board of Trustees

Revised. Modifications for
Order 716 to Requirement
R9.3.5 and footnote 1;
modifications to bring
compliance elements into
conformance with the
latest version of the ERO
Rules of Procedure.

2

January 22, 2010

Approved by FERC on January 21,
2010. Added Effective Date

Update

2

February 7, 2013

R9.1, R9.1.1, R9.1.2, R9.1.3, and
R9.1.4 and associated elements
approved by NERC Board of
Trustees for retirement as part of the
Paragraph 81 project (Project 201302) pending applicable regulatory
approval.

2

November 21,
2013

2.1

April 11, 2012

2.1

September 9,
2013

3

March 2014

R9.1, R9.1.1, R9.1.2, R9.1.3, and
R9.1.4 and associated elements
approved by FERC for retirement as
part of the Paragraph 81 project
(Project 2013-02)
Errata approved by the Standards
Committee; (Capitalized “Protection
System” in accordance with
Implementation Plan for Project
2007-17 approval of revised
definition of “Protection System”)
Informational filing submitted to
reflect the revised definition of
Protection System in accordance
with the Implementation Plan for the
revised term.
Modifications to implement the
recommendations of the five-year
review of NUC-001, which was
accepted by the Standards
Committee on October 17, 2013.

3

August 14, 2014

Adopted by the NERC Board of
Trustees

3

November 4,
2014

FERC letter order issued approving
NUC-001-3

Errata associated with
Project 2007-17

Revision

Page 12 of 13

Formatted Table

NUC-001-4— Nuclear Plant Interface Coordination

4

February 6, 2020

Adopted by the NERC Board of
Trustees

Revisions under Project
2017-07

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 R5:
The NUC FYRT recommended R5 be revised for consistency with R4 and to clarify that nuclear
plants must be operated to meet the Nuclear Plant Interface Requirements.
Rationale for R7 and R8:
The NUC FYRT recommended deleting “Protection Systems” in Requirements R7 and R8 since
it is a subset of the "nuclear plant design" and "electric system design" elements currently
contained in R7 and R8 respectively; and adding a parenthetical clause (e.g. protective setpoints)
to R7 following "nuclear plant design" and parenthetical clause (e.g. relay setpoints) to R8
following "electric system design."

Rationale for R9:
The NUC FYRT recommended that R9 be revised to clarify that all agreements do not have to
discuss each of the elements in R9, but that the sum total of the agreements need to address the
elements. In addition, for clarity in Part 9.4.1, the NUC FYRT recommended that "affecting the
NPIRs" be inserted following "Provisions for communications" and "applicable unique" be
inserted following ""definitions of."
Rationale for R9.3.7:
The term “Special Protection Systems” (SPS) was replaced with “Remedial Action Schemes”
(RAS) in order to align with other current NERC standards development work in Project 201005.2: Special Protection Systems. Project 2010-05.2 has proposed to replace SPS with RAS
throughout all of the NERC Standards in order to move to the use of a single term. RAS and SPS
have the same definition in the NERC Glossary of Terms.

Page 13 of 13

Exhibit A-6
Proposed Reliability Standard PRC-006-4
Clean

RELIABILITY | RESILIENCE | SECURITY

PRC-006-4 — Automatic Underfrequency Load Shedding

A. Introduction
1.
Title:
Automatic Underfrequency Load Shedding
2.

Number:

3.

Purpose: To establish design and documentation requirements for automatic
underfrequency load shedding (UFLS) programs to arrest declining frequency, assist
recovery of frequency following underfrequency events and provide last resort
system preservation measures.

4.

Applicability:

PRC-006-4

4.1. Planning Coordinators
4.2. UFLS entities shall mean all entities that are responsible for the ownership,
operation, or control of UFLS equipment as required by the UFLS program
established by the Planning Coordinators. Such entities may include one or
more of the following:
4.2.1 Transmission Owners
4.2.2 Distribution Providers
4.2.3 UFLS-Only Distribution Providers
4.3. Transmission Owners that own Elements identified in the UFLS program
established by the Planning Coordinators.
5.

Effective Date:
See Implementation Plan

B. Requirements and Measures
R1.

Each Planning Coordinator shall develop and document criteria, including
consideration of historical events and system studies, to select portions of the Bulk
Electric System (BES), including interconnected portions of the BES in adjacent
Planning Coordinator areas and Regional Entity areas that may form islands. [VRF:
Medium][Time Horizon: Long-term Planning]

M1. Each Planning Coordinator shall have evidence such as reports, or other documentation
of its criteria to select portions of the Bulk Electric System that may form islands
including how system studies and historical events were considered to develop the
criteria per Requirement R1.
R2.

Each Planning Coordinator shall identify one or more islands to serve as a basis for
designing its UFLS program including: [VRF: Medium][Time Horizon: Long-term
Planning]
2.1. Those islands selected by applying the criteria in Requirement R1, and

Page 1 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

2.2. Any portions of the BES designed to detach from the Interconnection (planned
islands) as a result of the operation of a relay scheme or Special Protection
System, and
2.3. A single island that includes all portions of the BES in either the Regional Entity
area or the Interconnection in which the Planning Coordinator’s area resides. If a
Planning Coordinator’s area resides in multiple Regional Entity areas, each of
those Regional Entity areas shall be identified as an island. Planning Coordinators
may adjust island boundaries to differ from Regional Entity area boundaries by
mutual consent where necessary for the sole purpose of producing contiguous
regional islands more suitable for simulation.
M2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s) as a basis
for designing a UFLS program that meet the criteria in Requirement R2, Parts 2.1
through 2.3.
R3.

Each Planning Coordinator shall develop a UFLS program, including notification of and
a schedule for implementation by UFLS entities within its area, that meets the
following performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s). [VRF:
High][Time Horizon: Long-term Planning]
3.1. Frequency shall remain above the Underfrequency Performance Characteristic
curve in PRC-006-4 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
3.2. Frequency shall remain below the Overfrequency Performance Characteristic
curve in PRC-006-4 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
3.3. Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two seconds
cumulatively per simulated event, and shall not exceed 1.10 per unit for longer
than 45 seconds cumulatively per simulated event at each generator bus and
generator step-up transformer high-side bus associated with each of the
following:
• Individual generating units greater than 20 MVA (gross nameplate rating)
directly connected to the BES
• Generating plants/facilities greater than 75 MVA (gross aggregate nameplate
rating) directly connected to the BES
• Facilities consisting of one or more units connected to the BES at a common
bus with total generation above 75 MVA gross nameplate rating.

M3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its UFLS program, including the
Page 2 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

notification of the UFLS entities of implementation schedule, that meet the criteria in
Requirement R3, Parts 3.1 through 3.3.
R4.

Each Planning Coordinator shall conduct and document a UFLS design assessment at
least once every five years that determines through dynamic simulation whether the
UFLS program design meets the performance characteristics in Requirement R3 for
each island identified in Requirement R2. The simulation shall model each of the
following: [VRF: High][Time Horizon: Long-term Planning]
4.1. Underfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip above the
Generator Underfrequency Trip Modeling curve in PRC-006-4 - Attachment 1.
4.2. Underfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip above
the Generator Underfrequency Trip Modeling curve in PRC-006-4 - Attachment 1.
4.3. Underfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-4 - Attachment 1.
4.4. Overfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-4 — Attachment 1.
4.5. Overfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip below
the Generator Overfrequency Trip Modeling curve in PRC-006-4 — Attachment 1.
4.6. Overfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-4 — Attachment 1.
4.7. Any automatic Load restoration that impacts frequency stabilization and operates
within the duration of the simulations run for the assessment.

M4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its UFLS design
assessment that demonstrates it meets Requirement R4, Parts 4.1 through 4.7.
R5.

Page 3 of 41

Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall coordinate its UFLS program design
with all other Planning Coordinators whose areas or portions of whose areas are also
part of the same identified island through one of the following: [VRF: High][Time
Horizon: Long-term Planning]

PRC-006-4 — Automatic Underfrequency Load Shedding
•

Develop a common UFLS program design and schedule for implementation per
Requirement R3 among the Planning Coordinators whose areas or portions of
whose areas are part of the same identified island, or

•

Conduct a joint UFLS design assessment per Requirement R4 among the Planning
Coordinators whose areas or portions of whose areas are part of the same
identified island, or

•

Conduct an independent UFLS design assessment per Requirement R4 for the
identified island, and in the event the UFLS design assessment fails to meet
Requirement R3, identify modifications to the UFLS program(s) to meet
Requirement R3 and report these modifications as recommendations to the other
Planning Coordinators whose areas or portions of whose areas are also part of
the same identified island and the ERO.

M5. Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall have dated evidence such as joint
UFLS program design documents, reports describing a joint UFLS design assessment,
letters that include recommendations, or other dated documentation demonstrating
that it coordinated its UFLS program design with all other Planning Coordinators whose
areas or portions of whose areas are also part of the same identified island per
Requirement R5.
R6.

Each Planning Coordinator shall maintain a UFLS database containing data necessary to
model its UFLS program for use in event analyses and assessments of the UFLS
program at least once each calendar year, with no more than 15 months between
maintenance activities. [VRF: Lower][Time Horizon: Long-term Planning]

M6. Each Planning Coordinator shall have dated evidence such as a UFLS database, data
requests, data input forms, or other dated documentation to show that it maintained a
UFLS database for use in event analyses and assessments of the UFLS program per
Requirement R6 at least once each calendar year, with no more than 15 months
between maintenance activities.
R7.

Each Planning Coordinator shall provide its UFLS database containing data necessary to
model its UFLS program to other Planning Coordinators within its Interconnection
within 30 calendar days of a request. [VRF: Lower][Time Horizon: Long-term Planning]

M7. Each Planning Coordinator shall have dated evidence such as letters, memorandums,
e-mails or other dated documentation that it provided their UFLS database to other
Planning Coordinators within their Interconnection within 30 calendar days of a
request per Requirement R7.
R8.

Page 4 of 41

Each UFLS entity shall provide data to its Planning Coordinator(s) according to the
format and schedule specified by the Planning Coordinator(s) to support maintenance
of each Planning Coordinator’s UFLS database. [VRF: Lower][Time Horizon: Long-term
Planning]

PRC-006-4 — Automatic Underfrequency Load Shedding

M8. Each UFLS Entity shall have dated evidence such as responses to data requests,
spreadsheets, letters or other dated documentation that it provided data to its
Planning Coordinator according to the format and schedule specified by the Planning
Coordinator to support maintenance of the UFLS database per Requirement R8.
R9.

Each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
as determined by its Planning Coordinator(s) in each Planning Coordinator area in
which it owns assets. [VRF: High][Time Horizon: Long-term Planning]

M9. Each UFLS Entity shall have dated evidence such as spreadsheets summarizing feeder
load armed with UFLS relays, spreadsheets with UFLS relay settings, or other dated
documentation that it provided automatic tripping of load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
per Requirement R9.
R10. Each Transmission Owner shall provide automatic switching of its existing capacitor
banks, Transmission Lines, and reactors to control over-voltage as a result of
underfrequency load shedding if required by the UFLS program and schedule for
implementation, including any Corrective Action Plan, as determined by the Planning
Coordinator(s) in each Planning Coordinator area in which the Transmission Owner
owns transmission. [VRF: High][Time Horizon: Long-term Planning]
M10. Each Transmission Owner shall have dated evidence such as relay settings, tripping
logic or other dated documentation that it provided automatic switching of its existing
capacitor banks, Transmission Lines, and reactors in order to control over-voltage as a
result of underfrequency load shedding if required by the UFLS program and schedule
for implementation, including any Corrective Action Plan, per Requirement R10.
R11. Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
conduct and document an assessment of the event within one year of event actuation
to evaluate: [VRF: Medium][Time Horizon: Operations Assessment]
11.1. The performance of the UFLS equipment,
11.2. The effectiveness of the UFLS program.
M11. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted an
event assessment of the performance of the UFLS equipment and the effectiveness of
the UFLS program per Requirement R11.
R12. Each Planning Coordinator, in whose islanding event assessment (per R11) UFLS
program deficiencies are identified, shall conduct and document a UFLS design
assessment to consider the identified deficiencies within two years of event actuation.
[VRF: Medium][Time Horizon: Operations Assessment]

Page 5 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

M12. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted a
UFLS design assessment per Requirements R12 and R4 if UFLS program deficiencies are
identified in R11.
R13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall coordinate its event assessment (in accordance
with Requirement R11) with all other Planning Coordinators whose areas or portions of
whose areas were also included in the same islanding event through one of the
following: [VRF: Medium][Time Horizon: Operations Assessment]
•

Conduct a joint event assessment per Requirement R11 among the Planning
Coordinators whose areas or portions of whose areas were included in the same
islanding event, or

•

Conduct an independent event assessment per Requirement R11 that reaches
conclusions and recommendations consistent with those of the event
assessments of the other Planning Coordinators whose areas or portions of
whose areas were included in the same islanding event, or

•

Conduct an independent event assessment per Requirement R11 and where the
assessment fails to reach conclusions and recommendations consistent with
those of the event assessments of the other Planning Coordinators whose areas
or portions of whose areas were included in the same islanding event, identify
differences in the assessments that likely resulted in the differences in the
conclusions and recommendations and report these differences to the other
Planning Coordinators whose areas or portions of whose areas were included in
the same islanding event and the ERO.

M13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall have dated evidence such as a joint assessment
report, independent assessment reports and letters describing likely reasons for
differences in conclusions and recommendations, or other dated documentation
demonstrating it coordinated its event assessment (per Requirement R11) with all
other Planning Coordinator(s) whose areas or portions of whose areas were also
included in the same islanding event per Requirement R13.
R14. Each Planning Coordinator shall respond to written comments submitted by UFLS
entities and Transmission Owners within its Planning Coordinator area following a
comment period and before finalizing its UFLS program, indicating in the written
response to comments whether changes will be made or reasons why changes will not
be made to the following [VRF: Lower][Time Horizon: Long-term Planning]:

Page 6 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

14.1. UFLS program, including a schedule for implementation
14.2. UFLS design assessment
14.3. Format and schedule of UFLS data submittal
M14. Each Planning Coordinator shall have dated evidence of responses, such as e-mails and
letters, to written comments submitted by UFLS entities and Transmission Owners
within its Planning Coordinator area following a comment period and before finalizing
its UFLS program per Requirement R14.
R15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall develop a Corrective Action Plan
and a schedule for implementation by the UFLS entities within its area. [VRF:
High][Time Horizon: Long-term Planning]
15.1. For UFLS design assessments performed under Requirement R4 or R5, the
Corrective Action Plan shall be developed within the five-year time frame
identified in Requirement R4.
15.2. For UFLS design assessments performed under Requirement R12, the Corrective
Action Plan shall be developed within the two-year time frame identified in
Requirement R12.
M15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall have a dated Corrective Action
Plan and a schedule for implementation by the UFLS entities within its area, that was
developed within the time frame identified in Part 15.1 or 15.2.

Page 7 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
Each Planning Coordinator and UFLS entity shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
•

Each Planning Coordinator shall retain the current evidence of Requirements
R1, R2, R3, R4, R5, R12, R14, and R15, Measures M1, M2, M3, M4, M5, M12,
M14, and M15 as well as any evidence necessary to show compliance since
the last compliance audit.

•

Each Planning Coordinator shall retain the current evidence of UFLS database
update in accordance with Requirement R6, Measure M6, and evidence of the
prior year’s UFLS database update.

•

Each Planning Coordinator shall retain evidence of any UFLS database
transmittal to another Planning Coordinator since the last compliance audit in
accordance with Requirement R7, Measure M7.

•

Each UFLS entity shall retain evidence of UFLS data transmittal to the Planning
Coordinator(s) since the last compliance audit in accordance with
Requirement R8, Measure M8.

•

Each UFLS entity shall retain the current evidence of adherence with the UFLS
program in accordance with Requirement R9, Measure M9, and evidence of
adherence since the last compliance audit.

•

Transmission Owner shall retain the current evidence of adherence with the
UFLS program in accordance with Requirement R10, Measure M10, and
evidence of adherence since the last compliance audit.

•

Each Planning Coordinator shall retain evidence of Requirements R11, and
R13, and Measures M11, and M13 for 6 calendar years.

If a Planning Coordinator or UFLS entity is found non-compliant, it shall keep
information related to the non-compliance until found compliant or for the
retention period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.

Page 8 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaints
1.4. Additional Compliance Information
None

Page 9 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

Violation Severity Levels
R#
R1

Lower VSL
N/A

Moderate VSL

High VSL

Severe VSL

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas that may
form islands.

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events and system studies, to
select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas
and Regional Entity areas, that
may form islands.

The Planning Coordinator failed
to develop and document
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas and
Regional Entity areas, that may
form islands.

The Planning Coordinator
identified an island(s) to serve

The Planning Coordinator
identified an island(s) to serve

OR
The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of system
studies, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas, that
may form islands.
R2

N/A

The Planning Coordinator
identified an island(s) to

Page 10 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

serve as a basis for designing
its UFLS program but failed to
include one (1) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its
UFLS program but failed to
include two (2) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its UFLS
program but failed to include all
of the Parts as specified in
Requirement R2, Parts 2.1, 2.2,
or 2.3.
OR
The Planning Coordinator failed
to identify any island(s) to serve
as a basis for designing its UFLS
program.

R3

N/A

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation
by UFLS entities within its
area where imbalance = [(load
— actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet one (1) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of
underfrequency conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation
by UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet two (2) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of underfrequency
conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified
island(s).,but failed to meet all
the performance characteristic
in Requirement R3, Parts 3.1,
3.2, and 3.3 in simulations of
underfrequency conditions.
OR
The Planning Coordinator failed
to develop a UFLS program
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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
including notification of and a
schedule for implementation by
UFLS entities within its area

R4

The Planning Coordinator
conducted and documented a
UFLS assessment at least
once every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics
in Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
one (1) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
two (2) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
three (3) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
R3 but simulation failed to
include four (4) or more of the
items as specified in
Requirement R4, Parts 4.1
through 4.7.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
R3 for each island identified in
Requirement R2

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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R5

N/A

N/A

N/A

The Planning Coordinator, whose
area or portions of whose area is
part of an island identified by it
or another Planning Coordinator
which includes multiple Planning
Coordinator areas or portions of
those areas, failed to coordinate
its UFLS program design through
one of the manners described in
Requirement R5.

R6

N/A

N/A

N/A

The Planning Coordinator failed
to maintain a UFLS database for
use in event analyses and
assessments of the UFLS
program at least once each
calendar year, with no more
than 15 months between
maintenance activities.

R7

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 30 calendar days
and up to and including 40
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 40 calendar days
but less than and including 50
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 50 calendar days
but less than and including 60
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 60 calendar days
following the request.
OR

Page 13 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator failed
to provide its UFLS database to
other Planning Coordinators.

R8

The UFLS entity provided data
to its Planning Coordinator(s)
less than or equal to 10
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 10 calendar days
but less than or equal to 15
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 15 calendar days
but less than or equal to 20
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data to
its Planning Coordinator(s) more
than 20 calendar days following
the schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided less
than 90% but more than (and
including) 85% of automatic
tripping of Load in accordance
with the UFLS program design

The UFLS entity provided less
than 85% of automatic tripping
of Load in accordance with the
UFLS program design and
schedule for implementation,

OR
The UFLS entity provided data
to its Planning Coordinator(s)
but the data was not
according to the format
specified by the Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.
R9

The UFLS entity provided less
than 100% but more than
(and including) 95% of
automatic tripping of Load in
accordance with the UFLS

The UFLS entity provided less
than 95% but more than (and
including) 90% of automatic
tripping of Load in accordance
with the UFLS program design

OR
The UFLS entity failed to provide
data to its Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.

Page 14 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

program design and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which
it owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

including any Corrective Action
Plan, as determined by the
Planning Coordinator(s) area in
which it owns assets.

R10

The Transmission Owner
provided less than 100% but
more than (and including)
95% automatic switching of
its existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 95% but
more than (and including)
90% automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 90% but
more than (and including) 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the UFLS
program and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission Owner
owns transmission.

The Transmission Owner
provided less than 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and reactors
to control over-voltage if
required by the UFLS program
and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each Planning
Coordinator area in which the
Transmission Owner owns
transmission.

R11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of the

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
Page 15 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than one year
but less than or equal to 13
months of actuation.

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than 13 months
but less than or equal to 14
months of actuation.

UFLS program, conducted and
documented an assessment of
the event and evaluated the
parts as specified in
Requirement R11, Parts 11.1
and 11.2 within a time greater
than 14 months but less than
or equal to 15 months of
actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the
initializing set points of the
UFLS program, conducted and
documented an assessment of
the event within one year of
event actuation but failed to
evaluate one (1) of the Parts
as specified in Requirement
R11, Parts11.1 or 11.2.

Severe VSL
conducted and documented an
assessment of the event and
evaluated the parts as specified
in Requirement R11, Parts 11.1
and 11.2 within a time greater
than 15 months of actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to conduct and document
an assessment of the event and
evaluate the Parts as specified in
Requirement R11, Parts 11.1 and
11.2.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
conducted and documented an
assessment of the event within
one year of event actuation but
failed to evaluate all of the Parts

Page 16 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
as specified in Requirement R11,
Parts 11.1 and 11.2.

R12

R13

N/A

N/A

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than two
years but less than or equal to
25 months of event actuation.

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than 25
months but less than or equal
to 26 months of event
actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, conducted and documented
a UFLS design assessment to
consider the identified
deficiencies greater than 26
months of event actuation.

N/A

N/A

The Planning Coordinator, in
whose area a BES islanding event
occurred that also included the
area(s) or portions of area(s) of
other Planning Coordinator(s) in
the same islanding event and
that resulted in system
frequency excursions below the
initializing set points of the UFLS

OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, failed to conduct and
document a UFLS design
assessment to consider the
identified deficiencies.

Page 17 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
program, failed to coordinate its
UFLS event assessment with all
other Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event in
one of the manners described in
Requirement R13

R14

N/A

N/A

N/A

The Planning Coordinator failed
to respond to written comments
submitted by UFLS entities and
Transmission Owners within its
Planning Coordinator area
following a comment period and
before finalizing its UFLS
program, indicating in the
written response to comments
whether changes were made or
reasons why changes were not
made to the items in Parts 14.1
through 14.3.

R15

N/A

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance
characteristics in Requirement

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance
characteristics in Requirement

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance
characteristics in Requirement
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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period of
up to 1 month.

R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period
greater than 1 month but not
more than 2 months.

R3, but failed to develop a
Corrective Action Plan and a
schedule for implementation by
the UFLS entities within its area.
OR
The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance
characteristics in Requirement
R3, and developed a Corrective
Action Plan and a schedule for
implementation by the UFLS
entities within its area, but
exceeded the permissible time
frame for development by a
period greater than 2 months.

Page 19 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

D. Regional Variances
D.A. Regional Variance for the Quebec Interconnection
The following Interconnection-wide variance shall be applicable in the Quebec
Interconnection and replaces, in their entirety, Requirements R3 and R4 and the
violation severity levels associated with Requirements R3 and R4.
Rationale for Requirement D.A.3:
There are two modifications for requirement D.A.3 :
1. 25% Generation Deficiency : Since the Quebec Interconnection has no potential
viable BES Island in underfrequency conditions, the largest generation deficiency
scenarios are limited to extreme contingencies not already covered by RAS.
Based on Hydro-Québec TransÉnergie Transmission Planning requirements, the
stability of the network shall be maintained for extreme contingencies using a case
representing internal transfers not expected to be exceeded 25% of the time.
The Hydro-Québec TransÉnergie defense plan to cover these extreme contingencies
includes two RAS (RPTC- generation rejection and remote load shedding and TDST a centralized UVLS) and the UFLS.
2. Frequency performance curve (attachment 1A) : Specific cases where a small
generation deficiency using a peak case scenario with the minimum requirement of
spinning reserve can lead to an acceptable frequency deviation in the Quebec
Interconnection while stabilizing between the PRC-006-2 requirement (59.3 Hz) and
the UFLS anti-stall threshold (59.0 Hz).
An increase of the anti-stall threshold to 59.3 Hz would correct this situation but would
cause frequent load shedding of customers without any gain of system reliability.
Therefore, it is preferable to lower the steady state frequency minimum value to 59.0
Hz.
The delay in the performance characteristics curve is harmonized between D.A.3 and
R.3 to 60 seconds.
Rationale for Requirements D.A.3.3. and D.A.4:
The Quebec Interconnection has its own definition of BES. In Quebec, the vast
majority of BES generating plants/facilities are not directly connected to the BES. For
simulations to take into account sufficient generating resources D.A.3.3 and D.A.4
need simply refer to BES generators, plants or facilities since these are listed in a
Registry approved by Québec’s Regulatory Body (Régie de l’Énergie).

D.A.3. Each Planning Coordinator shall develop a UFLS program, including notification
of and a schedule for implementation by UFLS entities within its area, that
meets the following performance characteristics in simulations of
underfrequency conditions resulting from each of these extreme events:

Page 20 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

•

Loss of the entire capability of a generating station.

•

Loss of all transmission circuits emanating from a generating station,
switching station, substation or dc terminal.

•

Loss of all transmission circuits on a common right-of-way.

•

Three-phase fault with failure of a circuit breaker to operate and correct
operation of a breaker failure protection system and its associated breakers.

•

Three-phase fault on a circuit breaker, with normal fault clearing.

•

The operation or partial operation of a RAS for an event or condition for
which it was not intended to operate.

[VRF: High][Time Horizon: Long-term Planning]
D.A.3.1.

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-4 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-4 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than
two seconds cumulatively per simulated event, and shall not exceed
1.10 per unit for longer than 45 seconds cumulatively per simulated
event at each Quebec BES generator bus and associated generator
step-up transformer high-side bus

M.D.A.3. Each Planning Coordinator shall have evidence such as reports,
memorandums, e-mails, program plans, or other documentation of its UFLS
program, including the notification of the UFLS entities of implementation
schedule, that meet the criteria in Requirement D.A.3 Parts D.A.3.1 through
D.A.3.3.
D.A.4. Each Planning Coordinator shall conduct and document a UFLS design
assessment at least once every five years that determines through dynamic
simulation whether the UFLS program design meets the performance
characteristics in Requirement D.A.3 for each island identified in Requirement
R2. The simulation shall model each of the following; [VRF: High][Time
Horizon: Long-term Planning]
D.A.4.1

Underfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip above the Generator
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PRC-006-4 — Automatic Underfrequency Load Shedding

Underfrequency Trip Modeling curve in PRC-006-4 - Attachment 1A,
and
D.A.4.2

Overfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip below the Generator
Overfrequency Trip Modeling curve in PRC-006-4 - Attachment 1A,
and

D.A.4.3

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.A.4. Each Planning Coordinator shall have dated evidence such as reports,
dynamic simulation models and results, or other dated documentation of its
UFLS design assessment that demonstrates it meets Requirement D.A.4
Parts D.A.4.1 through D.A.4.3.

Page 22 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

D#
DA3

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet two (2) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

Severe VSL
The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Parts D.A.3.1, D.A.3.2, and
D.A.3.3 in simulations of
underfrequency conditions
OR
The Planning Coordinator failed
to develop a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area.

DA4

N/A

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed
to include one (1) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include two (2) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include all of the items as

Page 23 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL
specified in Parts D.A.4.1,
D.A.4.2 or D.A.4.3.

High VSL

Severe VSL

specified in Parts D.A.4.1, D.A.4.2
or D.A.4.3.

specified in Parts D.A.4.1, D.A.4.2
and D.A.4.3.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.A.3

Page 24 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

D.B.

Regional Variance for the Western Electricity Coordinating Council
The following Interconnection-wide variance shall be applicable in the Western
Electricity Coordinating Council (WECC) and replaces, in their entirety, Requirements R1,
R2, R3, R4, R5, R11, R12, and R13.
D.B.1. Each Planning Coordinator shall participate in a joint regional review with the
other Planning Coordinators in the WECC Regional Entity area that develops and
documents criteria, including consideration of historical events and system
studies, to select portions of the Bulk Electric System (BES) that may form
islands. [VRF: Medium][Time Horizon: Long-term Planning]
M.D.B.1. Each Planning Coordinator shall have evidence such as reports, or other
documentation of its criteria, developed as part of the joint regional review
with other Planning Coordinators in the WECC Regional Entity area to select
portions of the Bulk Electric System that may form islands including how system
studies and historical events were considered to develop the criteria per
Requirement D.B.1.
D.B.2. Each Planning Coordinator shall identify one or more islands from the regional
review (per D.B.1) to serve as a basis for designing a region-wide coordinated
UFLS program including: [VRF: Medium][Time Horizon: Long-term Planning]
D.B.2.1. Those islands selected by applying the criteria in Requirement D.B.1,
and
D.B.2.2. Any portions of the BES designed to detach from the Interconnection
(planned islands) as a result of the operation of a relay scheme or
Special Protection System.
M.D.B.2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s),
from the regional review (per D.B.1), as a basis for designing a region-wide
coordinated UFLS program that meet the criteria in Requirement D.B.2 Parts
D.B.2.1 and D.B.2.2.
D.B.3. Each Planning Coordinator shall adopt a UFLS program, coordinated across the
WECC Regional Entity area, including notification of and a schedule for
implementation by UFLS entities within its area, that meets the following
performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s).
[VRF: High][Time Horizon: Long-term Planning]
D.B.3.1.

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-4 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and

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PRC-006-4 — Automatic Underfrequency Load Shedding

D.B.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-4 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and

D.B.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two
seconds cumulatively per simulated event, and shall not exceed 1.10
per unit for longer than 45 seconds cumulatively per simulated event
at each generator bus and generator step-up transformer high-side
bus associated with each of the following:
D.B.3.3.1. Individual generating units greater than 20 MVA (gross
nameplate rating) directly connected to the BES
D.B.3.3.2. Generating plants/facilities greater than 75 MVA (gross
aggregate nameplate rating) directly connected to the
BES
D.B.3.3.3. Facilities consisting of one or more units connected to
the BES at a common bus with total generation above 75
MVA gross nameplate rating.

M.D.B.3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its adoption of a UFLS
program, coordinated across the WECC Regional Entity area, including the
notification of the UFLS entities of implementation schedule, that meet the
criteria in Requirement D.B.3 Parts D.B.3.1 through D.B.3.3.
D.B.4. Each Planning Coordinator shall participate in and document a coordinated
UFLS design assessment with the other Planning Coordinators in the WECC
Regional Entity area at least once every five years that determines through
dynamic simulation whether the UFLS program design meets the performance
characteristics in Requirement D.B.3 for each island identified in Requirement
D.B.2. The simulation shall model each of the following: [VRF: High][Time
Horizon: Long-term Planning]
D.B.4.1.

Underfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip above the Generator Underfrequency Trip Modeling curve
in PRC-006-4 - Attachment 1.

D.B.4.2.

Underfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-4 - Attachment 1.

D.B.4.3.

Underfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
above 75 MVA (gross nameplate rating) that trip above the

Page 26 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

Generator Underfrequency Trip Modeling curve in PRC-006-4 Attachment 1.
D.B.4.4.

Overfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip below the Generator Overfrequency Trip Modeling curve in
PRC-006-4 — Attachment 1.

D.B.4.5.

Overfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-4 — Attachment 1.

D.B.4.6.

Overfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
above 75 MVA (gross nameplate rating) that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-4 —
Attachment 1.

D.B.4.7.

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.B.4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its participation
in a coordinated UFLS design assessment with the other Planning Coordinators in
the WECC Regional Entity area that demonstrates it meets Requirement D.B.4
Parts D.B.4.1 through D.B.4.7.
D.B.11.

Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
participate in and document a coordinated event assessment with all affected
Planning Coordinators to conduct and document an assessment of the event
within one year of event actuation to evaluate: [VRF: Medium][Time Horizon:
Operations Assessment]
D.B.11.1. The performance of the UFLS equipment,
D.B.11.2 The effectiveness of the UFLS program

M.D.B.11. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a coordinated event assessment of the performance of the UFLS
equipment and the effectiveness of the UFLS program per Requirement D.B.11.
D.B.12.

Each Planning Coordinator, in whose islanding event assessment (per D.B.11)
UFLS program deficiencies are identified, shall participate in and document a
coordinated UFLS design assessment of the UFLS program with the other

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PRC-006-4 — Automatic Underfrequency Load Shedding

Planning Coordinators in the WECC Regional Entity area to consider the
identified deficiencies within two years of event actuation. [VRF: Medium][Time
Horizon: Operations Assessment]
M.D.B.12. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a UFLS design assessment per Requirements D.B.12 and D.B.4 if
UFLS program deficiencies are identified in D.B.11.

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#
D.B.1

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical
events, to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical events
and system studies, to select
portions of the BES, including
interconnected portions of the
BES in adjacent Planning
Coordinator areas, that may form
islands

OR

Severe VSL
The Planning Coordinator failed
to participate in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of system studies,
to select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands

Page 29 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

D#
D.B.2

Lower VSL

Moderate VSL

High VSL

N/A
N/A

The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include one
(1) of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2

Severe VSL
The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include all
of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2
OR
The Planning Coordinator failed
to identify any island(s) from the
regional review to serve as a
basis for designing its UFLS
program.

D.B.3

N/A

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, or D.B.3.3 in
simulations of underfrequency
conditions

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that included
notification of and a schedule for
implementation by UFLS entities
within its area, but failed to meet
two (2) of the performance
characteristic in Requirement
D.B.3, Parts D.B.3.1, D.B.3.2, or
D.B.3.3 in simulations of
underfrequency conditions

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, and D.B.3.3 in
simulations of underfrequency
conditions

Page 30 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
OR
The Planning Coordinator failed
to adopt a UFLS program,
coordinated across the WECC
Regional Entity area, including
notification of and a schedule for
implementation by UFLS entities
within its area.

D.B.4

The Planning Coordinator
participated in and
documented a coordinated
UFLS assessment with the other
Planning Coordinators in the
WECC Regional Entity area at
least once every five years that
determines through dynamic
simulation whether the UFLS
program design meets the
performance characteristics in
Requirement D.B.3 for each
island identified in Requirement
D.B.2 but the simulation failed
to include one (1) of the items
as specified in Requirement
D.B.4, Parts D.B.4.1 through
D.B.4.7.

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include two
(2) of the items as specified in
Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include three
(3) of the items as specified in
Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include four
(4) or more of the items as
specified in Requirement D.B.4,
Parts D.B.4.1 through D.B.4.7.
OR

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator failed
to participate in and document a
coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2

D.B.11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below the
initializing set points of the
UFLS program, participated in
and documented a coordinated
event assessment with all
Planning Coordinators whose
areas or portions of whose
areas were also included in the
same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than one year but

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 13 months but

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 14 months but

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL
less than or equal to 13 months
of actuation.

Moderate VSL
less than or equal to 14 months
of actuation.

High VSL

Severe VSL

less than or equal to 15 months
of actuation.

time greater than 15 months of
actuation.

OR

OR

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event
within one year of event
actuation but failed to evaluate
one (1) of the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 or D.B.11.2.

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to participate in and
document a coordinated event
assessment with all Planning
Coordinators whose areas or
portion of whose areas were also
included in the same island event
and evaluate the parts as
specified in Requirement D.B.11,
Parts D.B.11.1 and D.B.11.2.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
Page 33 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
in the same islanding event
within one year of event
actuation but failed to evaluate
all of the parts as specified in
Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2.

D.B.12

N/A

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than two
years but less than or equal to 25
months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 25
months but less than or equal to
26 months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 26
months of event actuation.
OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, failed to participate in
and document a coordinated
UFLS design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
Page 34 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
to consider the identified
deficiencies

Page 35 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

E. Associated Documents
Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

May 25, 2010

Completed revision, merging and
updating PRC-006-0, PRC-007-0 and
PRC-009-0.

1

November 4, 2010

Adopted by the Board of Trustees

1

May 7, 2012

FERC Order issued approving PRC006-1 (approval becomes effective
July 10, 2012)

1

November 9, 2012

2

November 13, 2014

FERC Letter Order issued accepting
the modification of the VRF in R5
from (Medium to High) and the
modification of the VSL language in
R8.
Adopted by the Board of Trustees

Revisions made under
Project 2008-02:
Undervoltage Load
Shedding (UVLS) &
Underfrequency Load
Shedding (UFLS) to address
directive issued in FERC
Order No. 763.
Revisions to existing
Requirement R9 and
R10 and addition of
new Requirement
R15.

3

August 10, 2017

Adopted by the NERC Board of
Trustees

4

February 6, 2020

Adopted by NERC Board of Trustees

Revisions to the Regional
Variance for the Quebec
Interconnection.
Revisions under Project
2017-07

Page 36 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

Page 37 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

PRC-006-4 – Attachment 1
Underfrequency Load Shedding Program
Design Performance and Modeling Curves for
Requirements R3 Parts 3.1-3.2 and R4 Parts 4.1-4.6
63

Overfrequency Trip Settings
Must Be Modeled for Generators
That Trip Below the Generator
Overfrequency Trip Modeling
Curve

62

Simulated Frequency Must
Remain Between the
Overfrequency and
Underfrequency Performance
Characteristic Curves

60

59

58

Underfrequency Trip Settings
Must Be Modeled for Generators
That Trip Above the Generator
Underfrequency Trip Modeling
Curve

57
0.1

1

Time (sec)

10

100

Generator Overfrequency Trip Modeling (Requirement R4 Parts 4.4-4.6)
Overfrequency Performance Characteristic (Requirement R3 Part 3.2)
Underfrequency Performance Characteristic (Requirement R3 Part 3.1)
Generator Underfrequency Trip Modeling (Requirement R4 Parts 4.1-4.3)

Curve Definitions
Generator Overfrequency Trip Modeling

Overfrequency Performance Characteristic

t≤2s

t>2s

t≤4s

4 s < t ≤ 30 s

t > 30 s

f = 62.2
Hz

f = -0.686log(t) + 62.41
Hz

f = 61.8
Hz

f = -0.686log(t) + 62.21
Hz

f = 60.7
Hz

Generator Underfrequency Trip
Modeling

Underfrequency Performance Characteristic

Page 38 of 41

Frequency (Hz)

61

PRC-006-4 — Automatic Underfrequency Load Shedding
t≤2s

t>2s

t≤2s

2 s < t ≤ 60 s

t > 60 s

f = 57.8
Hz

f = 0.575log(t) + 57.63
Hz

f = 58.0
Hz

f = 0.575log(t) + 57.83
Hz

f = 59.3
Hz

Page 39 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

Page 40 of 41

PRC-006-4 — Automatic Underfrequency Load Shedding

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 R9:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a Planning Coordinator (PC)
assessment. The revised language adds clarity by requiring that each UFLS entity follow the
UFLS program, including any Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R10:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a PC assessment. The revised
language adds clarity by requiring that each UFLS entity follow the UFLS program, including any
Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R15:
Requirement R15 was added in response to the directive from FERC Order No. 763, which
raised concern that the standard failed to specify how soon an entity would need to implement
corrections after a deficiency is identified by a PC assessment. Requirement R15 addresses the
FERC directive by making explicit that if deficiencies are identified as a result of an assessment,
the PC shall develop a Corrective Action Plan and schedule for implementation by the UFLS
entities.
A “Corrective Action Plan” is defined in the NERC Glossary of Terms as, “a list of actions and an
associated timetable for implementation to remedy a specific problem.” Thus, the Corrective
Action Plan developed by the PC will identify the specific timeframe for an entity to implement
corrections to remedy any deficiencies identified by the PC as a result of an assessment.

Page 41 of 41

Exhibit A-6
Proposed Reliability Standard PRC-006-4
Redline to Last Approved (PRC-006-3)

RELIABILITY | RESILIENCE | SECURITY

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
A. Introduction
1.
Title:
Automatic Underfrequency Load Shedding
2.

Number:

3.

Purpose: To establish design and documentation requirements for automatic
underfrequency load shedding (UFLS) programs to arrest declining frequency, assist
recovery of frequency following underfrequency events and provide last resort
system preservation measures.

4.

Applicability:

PRC-006-3 4

4.1. Planning Coordinators
4.2. UFLS entities shall mean all entities that are responsible for the ownership,
operation, or control of UFLS equipment as required by the UFLS program
established by the Planning Coordinators. Such entities may include one or
more of the following:
4.2.1 Transmission Owners
4.2.2

4.2.2 Distribution Providers
4.2.3 UFLS-Only Distribution Providers1

4.3. Transmission Owners that own Elements identified in the UFLS program
established by the Planning Coordinators.
5.

Effective Date:
See Implementation Plan
This standard is effective on the first day of the first calendar quarter six months 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.

6.

Background:
PRC-006-2 was developed under Project 2008-02: Underfrequency Load Shedding
(UFLS). The drafting team revised PRC-006-1 for the purpose of addressing the
directive issued in FERC Order No. 763. Automatic Underfrequency Load Shedding and
Load Shedding Plans Reliability Standards, 139 FERC ¶ 61,098 (2012).

1

NERC Rules of Procedure, Appendix 5
https://www.nerc.com/FilingsOrders/us/RuleOfProcedureDL/NERC_ROP_Effective_20160504.pdf

Page 1 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
E.B.
R1.

Requirements and Measures
Each Planning Coordinator shall develop and document criteria, including
consideration of historical events and system studies, to select portions of the Bulk
Electric System (BES), including interconnected portions of the BES in adjacent
Planning Coordinator areas and Regional Entity areas that may form islands. [VRF:
Medium][Time Horizon: Long-term Planning]

M1. Each Planning Coordinator shall have evidence such as reports, or other documentation
of its criteria to select portions of the Bulk Electric System that may form islands
including how system studies and historical events were considered to develop the
criteria per Requirement R1.
R2.

Each Planning Coordinator shall identify one or more islands to serve as a basis for
designing its UFLS program including: [VRF: Medium][Time Horizon: Long-term
Planning]
2.1. Those islands selected by applying the criteria in Requirement R1, and
2.2. Any portions of the BES designed to detach from the Interconnection (planned
islands) as a result of the operation of a relay scheme or Special Protection
System, and
2.3. A single island that includes all portions of the BES in either the Regional Entity
area or the Interconnection in which the Planning Coordinator’s area resides. If a
Planning Coordinator’s area resides in multiple Regional Entity areas, each of
those Regional Entity areas shall be identified as an island. Planning Coordinators
may adjust island boundaries to differ from Regional Entity area boundaries by
mutual consent where necessary for the sole purpose of producing contiguous
regional islands more suitable for simulation.

M2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s) as a basis
for designing a UFLS program that meet the criteria in Requirement R2, Parts 2.1
through 2.3.
R3.

Each Planning Coordinator shall develop a UFLS program, including notification of and
a schedule for implementation by UFLS entities within its area, that meets the
following performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s). [VRF:
High][Time Horizon: Long-term Planning]
3.1. Frequency shall remain above the Underfrequency Performance Characteristic
curve in PRC-006-3 4 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
3.2. Frequency shall remain below the Overfrequency Performance Characteristic
curve in PRC-006-3 4 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
Page 2 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
3.3. Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two seconds
cumulatively per simulated event, and shall not exceed 1.10 per unit for longer
than 45 seconds cumulatively per simulated event at each generator bus and
generator step-up transformer high-side bus associated with each of the
following:
• Individual generating units greater than 20 MVA (gross nameplate rating)
directly connected to the BES
• Generating plants/facilities greater than 75 MVA (gross aggregate nameplate
rating) directly connected to the BES
• Facilities consisting of one or more units connected to the BES at a common
bus with total generation above 75 MVA gross nameplate rating.
M3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its UFLS program, including the
notification of the UFLS entities of implementation schedule, that meet the criteria in
Requirement R3, Parts 3.1 through 3.3.
R4.

Each Planning Coordinator shall conduct and document a UFLS design assessment at
least once every five years that determines through dynamic simulation whether the
UFLS program design meets the performance characteristics in Requirement R3 for
each island identified in Requirement R2. The simulation shall model each of the
following: [VRF: High][Time Horizon: Long-term Planning]
4.1. Underfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip above the
Generator Underfrequency Trip Modeling curve in PRC-006-3 4 - Attachment 1.
4.2. Underfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip above
the Generator Underfrequency Trip Modeling curve in PRC-006-3 4 - Attachment
1.
4.3. Underfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-3 4 - Attachment 1.
4.4. Overfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-3 4 — Attachment 1.
4.5. Overfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip below
the Generator Overfrequency Trip Modeling curve in PRC-006-3 4 — Attachment
1.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
4.6. Overfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-3 4 — Attachment 1.
4.7. Any automatic Load restoration that impacts frequency stabilization and operates
within the duration of the simulations run for the assessment.
M4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its UFLS design
assessment that demonstrates it meets Requirement R4, Parts 4.1 through 4.7.
R5.

Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall coordinate its UFLS program design
with all other Planning Coordinators whose areas or portions of whose areas are also
part of the same identified island through one of the following: [VRF: High][Time
Horizon: Long-term Planning]
•

Develop a common UFLS program design and schedule for implementation per
Requirement R3 among the Planning Coordinators whose areas or portions of
whose areas are part of the same identified island, or

•

Conduct a joint UFLS design assessment per Requirement R4 among the Planning
Coordinators whose areas or portions of whose areas are part of the same
identified island, or

•

Conduct an independent UFLS design assessment per Requirement R4 for the
identified island, and in the event the UFLS design assessment fails to meet
Requirement R3, identify modifications to the UFLS program(s) to meet
Requirement R3 and report these modifications as recommendations to the other
Planning Coordinators whose areas or portions of whose areas are also part of
the same identified island and the ERO.

M5. Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall have dated evidence such as joint
UFLS program design documents, reports describing a joint UFLS design assessment,
letters that include recommendations, or other dated documentation demonstrating
that it coordinated its UFLS program design with all other Planning Coordinators whose
areas or portions of whose areas are also part of the same identified island per
Requirement R5.
R6.

Each Planning Coordinator shall maintain a UFLS database containing data necessary to
model its UFLS program for use in event analyses and assessments of the UFLS
program at least once each calendar year, with no more than 15 months between
maintenance activities. [VRF: Lower][Time Horizon: Long-term Planning]

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
M6. Each Planning Coordinator shall have dated evidence such as a UFLS database, data
requests, data input forms, or other dated documentation to show that it maintained a
UFLS database for use in event analyses and assessments of the UFLS program per
Requirement R6 at least once each calendar year, with no more than 15 months
between maintenance activities.
R7.

Each Planning Coordinator shall provide its UFLS database containing data necessary to
model its UFLS program to other Planning Coordinators within its Interconnection
within 30 calendar days of a request. [VRF: Lower][Time Horizon: Long-term Planning]

M7. Each Planning Coordinator shall have dated evidence such as letters, memorandums,
e-mails or other dated documentation that it provided their UFLS database to other
Planning Coordinators within their Interconnection within 30 calendar days of a
request per Requirement R7.
R8.

Each UFLS entity shall provide data to its Planning Coordinator(s) according to the
format and schedule specified by the Planning Coordinator(s) to support maintenance
of each Planning Coordinator’s UFLS database. [VRF: Lower][Time Horizon: Long-term
Planning]

M8. Each UFLS Entity shall have dated evidence such as responses to data requests,
spreadsheets, letters or other dated documentation that it provided data to its
Planning Coordinator according to the format and schedule specified by the Planning
Coordinator to support maintenance of the UFLS database per Requirement R8.
R9.

Each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
as determined by its Planning Coordinator(s) in each Planning Coordinator area in
which it owns assets. [VRF: High][Time Horizon: Long-term Planning]

M9. Each UFLS Entity shall have dated evidence such as spreadsheets summarizing feeder
load armed with UFLS relays, spreadsheets with UFLS relay settings, or other dated
documentation that it provided automatic tripping of load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
per Requirement R9.
R10. Each Transmission Owner shall provide automatic switching of its existing capacitor
banks, Transmission Lines, and reactors to control over-voltage as a result of
underfrequency load shedding if required by the UFLS program and schedule for
implementation, including any Corrective Action Plan, as determined by the Planning
Coordinator(s) in each Planning Coordinator area in which the Transmission Owner
owns transmission. [VRF: High][Time Horizon: Long-term Planning]
M10. Each Transmission Owner shall have dated evidence such as relay settings, tripping
logic or other dated documentation that it provided automatic switching of its existing
capacitor banks, Transmission Lines, and reactors in order to control over-voltage as a
result of underfrequency load shedding if required by the UFLS program and schedule
for implementation, including any Corrective Action Plan, per Requirement R10.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R11. Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
conduct and document an assessment of the event within one year of event actuation
to evaluate: [VRF: Medium][Time Horizon: Operations Assessment]
11.1. The performance of the UFLS equipment,
11.2. The effectiveness of the UFLS program.
M11. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted an
event assessment of the performance of the UFLS equipment and the effectiveness of
the UFLS program per Requirement R11.
R12. Each Planning Coordinator, in whose islanding event assessment (per R11) UFLS
program deficiencies are identified, shall conduct and document a UFLS design
assessment to consider the identified deficiencies within two years of event actuation.
[VRF: Medium][Time Horizon: Operations Assessment]
M12. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted a
UFLS design assessment per Requirements R12 and R4 if UFLS program deficiencies are
identified in R11.
R13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall coordinate its event assessment (in accordance
with Requirement R11) with all other Planning Coordinators whose areas or portions of
whose areas were also included in the same islanding event through one of the
following: [VRF: Medium][Time Horizon: Operations Assessment]
•

Conduct a joint event assessment per Requirement R11 among the Planning
Coordinators whose areas or portions of whose areas were included in the same
islanding event, or

•

Conduct an independent event assessment per Requirement R11 that reaches
conclusions and recommendations consistent with those of the event
assessments of the other Planning Coordinators whose areas or portions of
whose areas were included in the same islanding event, or

•

Conduct an independent event assessment per Requirement R11 and where the
assessment fails to reach conclusions and recommendations consistent with
those of the event assessments of the other Planning Coordinators whose areas
or portions of whose areas were included in the same islanding event, identify
differences in the assessments that likely resulted in the differences in the
conclusions and recommendations and report these differences to the other
Planning Coordinators whose areas or portions of whose areas were included in
the same islanding event and the ERO.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
M13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall have dated evidence such as a joint assessment
report, independent assessment reports and letters describing likely reasons for
differences in conclusions and recommendations, or other dated documentation
demonstrating it coordinated its event assessment (per Requirement R11) with all
other Planning Coordinator(s) whose areas or portions of whose areas were also
included in the same islanding event per Requirement R13.
R14. Each Planning Coordinator shall respond to written comments submitted by UFLS
entities and Transmission Owners within its Planning Coordinator area following a
comment period and before finalizing its UFLS program, indicating in the written
response to comments whether changes will be made or reasons why changes will not
be made to the following [VRF: Lower][Time Horizon: Long-term Planning]:
14.1. UFLS program, including a schedule for implementation
14.2. UFLS design assessment
14.3. Format and schedule of UFLS data submittal
M14. Each Planning Coordinator shall have dated evidence of responses, such as e-mails and
letters, to written comments submitted by UFLS entities and Transmission Owners
within its Planning Coordinator area following a comment period and before finalizing
its UFLS program per Requirement R14.
R15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall develop a Corrective Action Plan
and a schedule for implementation by the UFLS entities within its area. [VRF:
High][Time Horizon: Long-term Planning]
15.1. For UFLS design assessments performed under Requirement R4 or R5, the
Corrective Action Plan shall be developed within the five-year time frame
identified in Requirement R4.
15.2. For UFLS design assessments performed under Requirement R12, the Corrective
Action Plan shall be developed within the two-year time frame identified in
Requirement R12.
M15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall have a dated Corrective Action
Plan and a schedule for implementation by the UFLS entities within its area, that was
developed within the time frame identified in Part 15.1 or 15.2.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

F.C.
1.

Compliance
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” (CEA)
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
Each Planning Coordinator and UFLS entity shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
•

Each Planning Coordinator shall retain the current evidence of Requirements
R1, R2, R3, R4, R5, R12, R14, and R15, Measures M1, M2, M3, M4, M5, M12,
M14, and M15 as well as any evidence necessary to show compliance since
the last compliance audit.

•

Each Planning Coordinator shall retain the current evidence of UFLS database
update in accordance with Requirement R6, Measure M6, and evidence of the
prior year’s UFLS database update.

•

Each Planning Coordinator shall retain evidence of any UFLS database
transmittal to another Planning Coordinator since the last compliance audit in
accordance with Requirement R7, Measure M7.

•

Each UFLS entity shall retain evidence of UFLS data transmittal to the Planning
Coordinator(s) since the last compliance audit in accordance with
Requirement R8, Measure M8.

•

Each UFLS entity shall retain the current evidence of adherence with the UFLS
program in accordance with Requirement R9, Measure M9, and evidence of
adherence since the last compliance audit.

•

Transmission Owner shall retain the current evidence of adherence with the
UFLS program in accordance with Requirement R10, Measure M10, and
evidence of adherence since the last compliance audit.

•

Each Planning Coordinator shall retain evidence of Requirements R11, and
R13, and Measures M11, and M13 for 6 calendar years.

If a Planning Coordinator or UFLS entity is found non-compliant, it shall keep
information related to the non-compliance until found compliant or for the
retention period specified above, whichever is longer.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaints
1.4. Additional Compliance Information
None

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

2.
R#
R1

Violation Severity Levels
Lower VSL

N/A

Moderate VSL

High VSL

Severe VSL

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas that may
form islands.

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events and system studies, to
select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas
and Regional Entity areas, that
may form islands.

The Planning Coordinator failed
to develop and document
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas and
Regional Entity areas, that may
form islands.

The Planning Coordinator
identified an island(s) to serve

The Planning Coordinator
identified an island(s) to serve

OR
The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of system
studies, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas, that
may form islands.
R2

N/A

The Planning Coordinator
identified an island(s) to

Page 10 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

serve as a basis for designing
its UFLS program but failed to
include one (1) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its
UFLS program but failed to
include two (2) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its UFLS
program but failed to include all
of the Parts as specified in
Requirement R2, Parts 2.1, 2.2,
or 2.3.
OR
The Planning Coordinator failed
to identify any island(s) to serve
as a basis for designing its UFLS
program.

R3

N/A

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation
by UFLS entities within its
area where imbalance = [(load
— actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet one (1) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of
underfrequency conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation
by UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet two (2) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of underfrequency
conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified
island(s).,but failed to meet all
the performance characteristic
in Requirement R3, Parts 3.1,
3.2, and 3.3 in simulations of
underfrequency conditions.
OR
The Planning Coordinator failed
to develop a UFLS program
Page 11 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
including notification of and a
schedule for implementation by
UFLS entities within its area

R4

The Planning Coordinator
conducted and documented a
UFLS assessment at least
once every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics
in Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
one (1) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
two (2) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
three (3) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
R3 but simulation failed to
include four (4) or more of the
items as specified in
Requirement R4, Parts 4.1
through 4.7.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
R3 for each island identified in
Requirement R2

Page 12 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R5

N/A

N/A

N/A

The Planning Coordinator, whose
area or portions of whose area is
part of an island identified by it
or another Planning Coordinator
which includes multiple Planning
Coordinator areas or portions of
those areas, failed to coordinate
its UFLS program design through
one of the manners described in
Requirement R5.

R6

N/A

N/A

N/A

The Planning Coordinator failed
to maintain a UFLS database for
use in event analyses and
assessments of the UFLS
program at least once each
calendar year, with no more
than 15 months between
maintenance activities.

R7

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 30 calendar days
and up to and including 40
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 40 calendar days
but less than and including 50
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 50 calendar days
but less than and including 60
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 60 calendar days
following the request.
OR

Page 13 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator failed
to provide its UFLS database to
other Planning Coordinators.

R8

The UFLS entity provided data
to its Planning Coordinator(s)
less than or equal to 10
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 10 calendar days
but less than or equal to 15
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 15 calendar days
but less than or equal to 20
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data to
its Planning Coordinator(s) more
than 20 calendar days following
the schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided less
than 90% but more than (and
including) 85% of automatic
tripping of Load in accordance
with the UFLS program design

The UFLS entity provided less
than 85% of automatic tripping
of Load in accordance with the
UFLS program design and
schedule for implementation,

OR
The UFLS entity provided data
to its Planning Coordinator(s)
but the data was not
according to the format
specified by the Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.
R9

The UFLS entity provided less
than 100% but more than
(and including) 95% of
automatic tripping of Load in
accordance with the UFLS

The UFLS entity provided less
than 95% but more than (and
including) 90% of automatic
tripping of Load in accordance
with the UFLS program design

OR
The UFLS entity failed to provide
data to its Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.

Page 14 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

program design and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which
it owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

including any Corrective Action
Plan, as determined by the
Planning Coordinator(s) area in
which it owns assets.

R10

The Transmission Owner
provided less than 100% but
more than (and including)
95% automatic switching of
its existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 95% but
more than (and including)
90% automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 90% but
more than (and including) 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the UFLS
program and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission Owner
owns transmission.

The Transmission Owner
provided less than 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and reactors
to control over-voltage if
required by the UFLS program
and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each Planning
Coordinator area in which the
Transmission Owner owns
transmission.

R11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of the

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,

Page 15 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than one year
but less than or equal to 13
months of actuation.

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than 13 months
but less than or equal to 14
months of actuation.

UFLS program, conducted and
documented an assessment of
the event and evaluated the
parts as specified in
Requirement R11, Parts 11.1
and 11.2 within a time greater
than 14 months but less than
or equal to 15 months of
actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the
initializing set points of the
UFLS program, conducted and
documented an assessment of
the event within one year of
event actuation but failed to
evaluate one (1) of the Parts
as specified in Requirement
R11, Parts11.1 or 11.2.

Severe VSL
conducted and documented an
assessment of the event and
evaluated the parts as specified
in Requirement R11, Parts 11.1
and 11.2 within a time greater
than 15 months of actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to conduct and document
an assessment of the event and
evaluate the Parts as specified in
Requirement R11, Parts 11.1 and
11.2.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
conducted and documented an
assessment of the event within
one year of event actuation but
failed to evaluate all of the Parts

Page 16 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
as specified in Requirement R11,
Parts 11.1 and 11.2.

R12

R13

N/A

N/A

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than two
years but less than or equal to
25 months of event actuation.

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than 25
months but less than or equal
to 26 months of event
actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, conducted and documented
a UFLS design assessment to
consider the identified
deficiencies greater than 26
months of event actuation.

N/A

N/A

The Planning Coordinator, in
whose area a BES islanding event
occurred that also included the
area(s) or portions of area(s) of
other Planning Coordinator(s) in
the same islanding event and
that resulted in system
frequency excursions below the
initializing set points of the UFLS

OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, failed to conduct and
document a UFLS design
assessment to consider the
identified deficiencies.

Page 17 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
program, failed to coordinate its
UFLS event assessment with all
other Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event in
one of the manners described in
Requirement R13

R14

N/A

N/A

N/A

The Planning Coordinator failed
to respond to written comments
submitted by UFLS entities and
Transmission Owners within its
Planning Coordinator area
following a comment period and
before finalizing its UFLS
program, indicating in the
written response to comments
whether changes were made or
reasons why changes were not
made to the items in Parts 14.1
through 14.3.

R15

N/A

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance
characteristics in Requirement

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance
characteristics in Requirement

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance
characteristics in Requirement
Page 18 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period of
up to 1 month.

R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period
greater than 1 month but not
more than 2 months.

R3, but failed to develop a
Corrective Action Plan and a
schedule for implementation by
the UFLS entities within its area.
OR
The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance
characteristics in Requirement
R3, and developed a Corrective
Action Plan and a schedule for
implementation by the UFLS
entities within its area, but
exceeded the permissible time
frame for development by a
period greater than 2 months.

Page 19 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D. Regional Variances
D.A. Regional Variance for the Quebec Interconnection
The following Interconnection-wide variance shall be applicable in the Quebec
Interconnection and replaces, in their entirety, Requirements R3 and R4 and the
violation severity levels associated with Requirements R3 and R4.
Rationale for Requirement D.A.3:
There are two modifications for requirement D.A.3 :
1. 25% Generation Deficiency : Since the Quebec Interconnection has no potential
viable BES Island in underfrequency conditions, the largest generation deficiency
scenarios are limited to extreme contingencies not already covered by RAS.
Based on Hydro-Québec TransÉnergie Transmission Planning requirements, the
stability of the network shall be maintained for extreme contingencies using a case
representing internal transfers not expected to be exceeded 25% of the time.
The Hydro-Québec TransÉnergie defense plan to cover these extreme contingencies
includes two RAS (RPTC- generation rejection and remote load shedding and TDST a centralized UVLS) and the UFLS.
2. Frequency performance curve (attachment 1A) : Specific cases where a small
generation deficiency using a peak case scenario with the minimum requirement of
spinning reserve can lead to an acceptable frequency deviation in the Quebec
Interconnection while stabilizing between the PRC-006-2 requirement (59.3 Hz) and
the UFLS anti-stall threshold (59.0 Hz).
An increase of the anti-stall threshold to 59.3 Hz would correct this situation but would
cause frequent load shedding of customers without any gain of system reliability.
Therefore, it is preferable to lower the steady state frequency minimum value to 59.0
Hz.
The delay in the performance characteristics curve is harmonized between D.A.3 and
R.3 to 60 seconds.
Rationale for Requirements D.A.3.3. and D.A.4:
The Quebec Interconnection has its own definition of BES. In Quebec, the vast
majority of BES generating plants/facilities are not directly connected to the BES. For
simulations to take into account sufficient generating resources D.A.3.3 and D.A.4
need simply refer to BES generators, plants or facilities since these are listed in a
Registry approved by Québec’s Regulatory Body (Régie de l’Énergie).

D.A.3. Each Planning Coordinator shall develop a UFLS program, including notification
of and a schedule for implementation by UFLS entities within its area, that

Page 20 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
meets the following performance characteristics in simulations of
underfrequency conditions resulting from each of these extreme events:
•

Loss of the entire capability of a generating station.

•

Loss of all transmission circuits emanating from a generating
station, switching station, substation or dc terminal.

•

Loss of all transmission circuits on a common right-of-way.

•

Three-phase fault with failure of a circuit breaker to operate and
correct operation of a breaker failure protection system and its
associated breakers.

•

Three-phase fault on a circuit breaker, with normal fault clearing.

•

The operation or partial operation of a RAS for an event or
condition for which it was not intended to operate.

[VRF: High][Time Horizon: Long-term Planning]
D.A.3.1.

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-3 4 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-3 4 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than
two seconds cumulatively per simulated event, and shall not exceed
1.10 per unit for longer than 45 seconds cumulatively per simulated
event at each Quebec BES generator bus and associated generator
step-up transformer high-side bus

M.D.A.3. Each Planning Coordinator shall have evidence such as reports,
memorandums, e-mails, program plans, or other documentation of its UFLS
program, including the notification of the UFLS entities of implementation
schedule, that meet the criteria in Requirement D.A.3 Parts D.A.3.1 through
D.A.3.3.
D.A.4. Each Planning Coordinator shall conduct and document a UFLS design
assessment at least once every five years that determines through dynamic
simulation whether the UFLS program design meets the performance
characteristics in Requirement D.A.3 for each island identified in Requirement
Page 21 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R2. The simulation shall model each of the following; [VRF: High][Time
Horizon: Long-term Planning]
D.A.4.1

Underfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip above the Generator
Underfrequency Trip Modeling curve in PRC-006-3 4 - Attachment
1A, and

D.A.4.2

Overfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip below the Generator
Overfrequency Trip Modeling curve in PRC-006-3 4 - Attachment
1A, and

D.A.4.3

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.A.4. Each Planning Coordinator shall have dated evidence such as reports,
dynamic simulation models and results, or other dated documentation of its
UFLS design assessment that demonstrates it meets Requirement D.A.4
Parts D.A.4.1 through D.A.4.3.

Page 22 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#
DA3

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet two (2) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

Severe VSL
The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Parts D.A.3.1, D.A.3.2, and
D.A.3.3 in simulations of
underfrequency conditions
OR
The Planning Coordinator failed
to develop a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area.

DA4

N/A

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed
to include one (1) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include two (2) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include all of the items as
Page 23 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL
specified in Parts D.A.4.1,
D.A.4.2 or D.A.4.3.

High VSL

Severe VSL

specified in Parts D.A.4.1, D.A.4.2
or D.A.4.3.

specified in Parts D.A.4.1, D.A.4.2
and D.A.4.3.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.A.3

Page 24 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D.B.

Regional Variance for the Western Electricity Coordinating Council
The following Interconnection-wide variance shall be applicable in the Western
Electricity Coordinating Council (WECC) and replaces, in their entirety, Requirements R1,
R2, R3, R4, R5, R11, R12, and R13.
D.B.1. Each Planning Coordinator shall participate in a joint regional review with the
other Planning Coordinators in the WECC Regional Entity area that develops and
documents criteria, including consideration of historical events and system
studies, to select portions of the Bulk Electric System (BES) that may form
islands. [VRF: Medium][Time Horizon: Long-term Planning]
M.D.B.1. Each Planning Coordinator shall have evidence such as reports, or other
documentation of its criteria, developed as part of the joint regional review
with other Planning Coordinators in the WECC Regional Entity area to select
portions of the Bulk Electric System that may form islands including how system
studies and historical events were considered to develop the criteria per
Requirement D.B.1.
D.B.2. Each Planning Coordinator shall identify one or more islands from the regional
review (per D.B.1) to serve as a basis for designing a region-wide coordinated
UFLS program including: [VRF: Medium][Time Horizon: Long-term Planning]
D.B.2.1. Those islands selected by applying the criteria in Requirement D.B.1,
and
D.B.2.2. Any portions of the BES designed to detach from the Interconnection
(planned islands) as a result of the operation of a relay scheme or
Special Protection System.
M.D.B.2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s),
from the regional review (per D.B.1), as a basis for designing a region-wide
coordinated UFLS program that meet the criteria in Requirement D.B.2 Parts
D.B.2.1 and D.B.2.2.
D.B.3. Each Planning Coordinator shall adopt a UFLS program, coordinated across the
WECC Regional Entity area, including notification of and a schedule for
implementation by UFLS entities within its area, that meets the following
performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s).
[VRF: High][Time Horizon: Long-term Planning]
D.B.3.1.

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-3 4 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and
Page 25 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D.B.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-3 4 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and

D.B.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two
seconds cumulatively per simulated event, and shall not exceed 1.10
per unit for longer than 45 seconds cumulatively per simulated event
at each generator bus and generator step-up transformer high-side
bus associated with each of the following:
D.B.3.3.1. Individual generating units greater than 20 MVA (gross
nameplate rating) directly connected to the BES
D.B.3.3.2. Generating plants/facilities greater than 75 MVA (gross
aggregate nameplate rating) directly connected to the
BES
D.B.3.3.3. Facilities consisting of one or more units connected to
the BES at a common bus with total generation above 75
MVA gross nameplate rating.

M.D.B.3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its adoption of a UFLS
program, coordinated across the WECC Regional Entity area, including the
notification of the UFLS entities of implementation schedule, that meet the
criteria in Requirement D.B.3 Parts D.B.3.1 through D.B.3.3.
D.B.4. Each Planning Coordinator shall participate in and document a coordinated
UFLS design assessment with the other Planning Coordinators in the WECC
Regional Entity area at least once every five years that determines through
dynamic simulation whether the UFLS program design meets the performance
characteristics in Requirement D.B.3 for each island identified in Requirement
D.B.2. The simulation shall model each of the following: [VRF: High][Time
Horizon: Long-term Planning]
D.B.4.1.

Underfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip above the Generator Underfrequency Trip Modeling curve
in PRC-006-3 4 - Attachment 1.

D.B.4.2.

Underfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-3 4 - Attachment 1.

D.B.4.3.

Underfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
Page 26 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
above 75 MVA (gross nameplate rating) that trip above the
Generator Underfrequency Trip Modeling curve in PRC-006-3 4 Attachment 1.
D.B.4.4.

Overfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip below the Generator Overfrequency Trip Modeling curve in
PRC-006-3 4 — Attachment 1.

D.B.4.5.

Overfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-3 4 — Attachment 1.

D.B.4.6.

Overfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
above 75 MVA (gross nameplate rating) that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-3 4 —
Attachment 1.

D.B.4.7.

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.B.4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its participation
in a coordinated UFLS design assessment with the other Planning Coordinators in
the WECC Regional Entity area that demonstrates it meets Requirement D.B.4
Parts D.B.4.1 through D.B.4.7.
D.B.11.

Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
participate in and document a coordinated event assessment with all affected
Planning Coordinators to conduct and document an assessment of the event
within one year of event actuation to evaluate: [VRF: Medium][Time Horizon:
Operations Assessment]
D.B.11.1. The performance of the UFLS equipment,
D.B.11.2 The effectiveness of the UFLS program

M.D.B.11. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a coordinated event assessment of the performance of the UFLS
equipment and the effectiveness of the UFLS program per Requirement D.B.11.

Page 27 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D.B.12.

Each Planning Coordinator, in whose islanding event assessment (per D.B.11)
UFLS program deficiencies are identified, shall participate in and document a
coordinated UFLS design assessment of the UFLS program with the other
Planning Coordinators in the WECC Regional Entity area to consider the
identified deficiencies within two years of event actuation. [VRF: Medium][Time
Horizon: Operations Assessment]

M.D.B.12. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a UFLS design assessment per Requirements D.B.12 and D.B.4 if
UFLS program deficiencies are identified in D.B.11.

Page 28 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#
D.B.1

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical
events, to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical events
and system studies, to select
portions of the BES, including
interconnected portions of the
BES in adjacent Planning
Coordinator areas, that may form
islands

OR

Severe VSL
The Planning Coordinator failed
to participate in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of system studies,
to select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands
Page 29 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#
D.B.2

Lower VSL

Moderate VSL

High VSL

N/A
N/A

The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include one
(1) of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2

Severe VSL
The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include all
of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2
OR
The Planning Coordinator failed
to identify any island(s) from the
regional review to serve as a
basis for designing its UFLS
program.

D.B.3

N/A

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, or D.B.3.3 in

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that included
notification of and a schedule for
implementation by UFLS entities
within its area, but failed to meet
two (2) of the performance
characteristic in Requirement
D.B.3, Parts D.B.3.1, D.B.3.2, or
D.B.3.3 in simulations of
underfrequency conditions

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, and D.B.3.3 in

Page 30 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

simulations of underfrequency
conditions

Severe VSL
simulations of underfrequency
conditions
OR
The Planning Coordinator failed
to adopt a UFLS program,
coordinated across the WECC
Regional Entity area, including
notification of and a schedule for
implementation by UFLS entities
within its area.

D.B.4

The Planning Coordinator
participated in and
documented a coordinated
UFLS assessment with the other
Planning Coordinators in the
WECC Regional Entity area at
least once every five years that
determines through dynamic
simulation whether the UFLS
program design meets the
performance characteristics in
Requirement D.B.3 for each
island identified in Requirement
D.B.2 but the simulation failed
to include one (1) of the items
as specified in Requirement

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include two
(2) of the items as specified in

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include three
(3) of the items as specified in

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include four
(4) or more of the items as

Page 31 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL
D.B.4, Parts D.B.4.1 through
D.B.4.7.

Moderate VSL

High VSL

Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

Severe VSL
specified in Requirement D.B.4,
Parts D.B.4.1 through D.B.4.7.
OR
The Planning Coordinator failed
to participate in and document a
coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2

D.B.11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below the
initializing set points of the
UFLS program, participated in
and documented a coordinated
event assessment with all
Planning Coordinators whose
areas or portions of whose
areas were also included in the

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
Page 32 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than one year but
less than or equal to 13 months
of actuation.

evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 13 months but
less than or equal to 14 months
of actuation.

evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 14 months but
less than or equal to 15 months
of actuation.

evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 15 months of
actuation.

OR

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to participate in and
document a coordinated event
assessment with all Planning
Coordinators whose areas or
portion of whose areas were also
included in the same island event
and evaluate the parts as
specified in Requirement D.B.11,
Parts D.B.11.1 and D.B.11.2.

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event
within one year of event
actuation but failed to evaluate
one (1) of the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 or D.B.11.2.

Severe VSL

OR

OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
Page 33 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event
within one year of event
actuation but failed to evaluate
all of the parts as specified in
Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2.

D.B.12

N/A

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than two
years but less than or equal to 25
months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 25
months but less than or equal to
26 months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 26
months of event actuation.
OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, failed to participate in
Page 34 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
and document a coordinated
UFLS design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies

Page 35 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
E. Associated Documents
Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

May 25, 2010

Completed revision, merging and
updating PRC-006-0, PRC-007-0 and
PRC-009-0.

1

November 4, 2010

Adopted by the Board of Trustees

1

May 7, 2012

FERC Order issued approving PRC006-1 (approval becomes effective
July 10, 2012)

1

November 9, 2012

2

November 13, 2014

FERC Letter Order issued accepting
the modification of the VRF in R5
from (Medium to High) and the
modification of the VSL language in
R8.
Adopted by the Board of Trustees

Revisions made under
Project 2008-02:
Undervoltage Load
Shedding (UVLS) &
Underfrequency Load
Shedding (UFLS) to address
directive issued in FERC
Order No. 763.
Revisions to existing
Requirement R9 and
R10 and addition of
new Requirement
R15.

3

August 10, 2017

Adopted by the NERC Board of
Trustees

4

February 6, 2020

Adopted by NERC Board of Trustees

Revisions to the Regional
Variance for the Quebec
Interconnection.
Revisions under Project
2017-07

Page 36 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

PRC-006-3 4 – Attachment 1
Underfrequency Load Shedding Program
Design Performance and Modeling Curves for
Requirements R3 Parts 3.1-3.2 and R4 Parts 4.1-4.6
63

Overfrequency Trip Settings
Must Be Modeled for Generators
That Trip Below the Generator
Overfrequency Trip Modeling
Curve

62

Simulated Frequency Must
Remain Between the
Overfrequency and
Underfrequency Performance
Characteristic Curves

60

59

58

Underfrequency Trip Settings
Must Be Modeled for Generators
That Trip Above the Generator
Underfrequency Trip Modeling
Curve

57
1

0.1

Time (sec)

10

100

Generator Overfrequency Trip Modeling (Requirement R4 Parts 4.4-4.6)
Overfrequency Performance Characteristic (Requirement R3 Part 3.2)
Underfrequency Performance Characteristic (Requirement R3 Part 3.1)
Generator Underfrequency Trip Modeling (Requirement R4 Parts 4.1-4.3)

Curve Definitions
Generator Overfrequency Trip Modeling

Overfrequency Performance Characteristic

t≤2s

t≤4s

t>2s

4 s < t ≤ 30 s

t > 30 s

Page 37 of 40

Frequency (Hz)

61

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
f = 62.2
Hz

f = -0.686log(t) + 62.41
Hz

f = 61.8
Hz

f = -0.686log(t) + 62.21
Hz

f = 60.7
Hz

Generator Underfrequency Trip
Modeling

Underfrequency Performance Characteristic

t≤2s

t>2s

t≤2s

2 s < t ≤ 60 s

t > 60 s

f = 57.8
Hz

f = 0.575log(t) + 57.63
Hz

f = 58.0
Hz

f = 0.575log(t) + 57.83
Hz

f = 59.3
Hz

Page 38 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

Page 39 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

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 R9:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a Planning Coordinator (PC)
assessment. The revised language adds clarity by requiring that each UFLS entity follow the
UFLS program, including any Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R10:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a PC assessment. The revised
language adds clarity by requiring that each UFLS entity follow the UFLS program, including any
Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R15:
Requirement R15 was added in response to the directive from FERC Order No. 763, which
raised concern that the standard failed to specify how soon an entity would need to implement
corrections after a deficiency is identified by a PC assessment. Requirement R15 addresses the
FERC directive by making explicit that if deficiencies are identified as a result of an assessment,
the PC shall develop a Corrective Action Plan and schedule for implementation by the UFLS
entities.
A “Corrective Action Plan” is defined in the NERC Glossary of Terms as, “a list of actions and an
associated timetable for implementation to remedy a specific problem.” Thus, the Corrective
Action Plan developed by the PC will identify the specific timeframe for an entity to implement
corrections to remedy any deficiencies identified by the PC as a result of an assessment.

Page 40 of 40

Exhibit A-7
Proposed Reliability Standard TOP-003-4
Clean

RELIABILITY | RESILIENCE | SECURITY

TOP-003-4 — Operational Reliability Data

A. Introduction
1.

Title: Operational Reliability Data

2.

Number: TOP-003-4

3.

Purpose: To ensure that the Transmission Operator and Balancing Authority have
data needed to fulfill their operational and planning responsibilities.

4.

Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Generator Owner
4.4. Generator Operator
4.5. Transmission Owner
4.6. Distribution Provider

5.

Effective Date: See Implementation Plan.

B. Requirements and Measures
R1. Each Transmission Operator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include, but not be limited to:
[Violation Risk Factor: Low] [Time Horizon: Operations Planning]
1.1.

A list of data and information needed by the Transmission Operator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data as
deemed necessary by the Transmission Operator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

M1. Each Transmission Operator shall make available its dated, current, in force
documented specification for data.
R2.

Each Balancing Authority shall maintain a documented specification for the data
necessary for it to perform its analysis functions and Real-time monitoring. The data
specification shall include, but not be limited to: [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]

Page 1 of 10

TOP-003-4 — Operational Reliability Data

2.1.

A list of data and information needed by the Balancing Authority to support
its analysis functions and Real-time monitoring.

2.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

2.3.

A periodicity for providing data.

2.4.

The deadline by which the respondent is to provide the indicated data.

M2. Each Balancing Authority shall make available its dated, current, in force documented
specification for data.
R3. Each Transmission Operator shall distribute its data specification to entities that have
data required by the Transmission Operator’s Operational Planning Analyses, Realtime monitoring, and Real-time Assessment. [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]
M3. Each Transmission Operator shall make available evidence that it has distributed its
data specification to entities that have data required by the Transmission Operator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments.
Such evidence could include but is not limited to web postings with an electronic
notice of the posting, dated operator logs, voice recordings, postal receipts showing
the recipient, date and contents, or e-mail records.
R4. Each Balancing Authority shall distribute its data specification to entities that have
data required by the Balancing Authority’s analysis functions and Real-time
monitoring. [Violation Risk Factor: Low] [Time Horizon: Operations Planning]
M4. Each Balancing Authority shall make available evidence that it has distributed its data
specification to entities that have data required by the Balancing Authority’s analysis
functions and Real-time monitoring. Such evidence could include but is not limited to
web postings with an electronic notice of the posting, dated operator logs, voice
recordings, postal receipts showing the recipient, or e-mail records.
R5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Owner, and Distribution Provider receiving a data
specification in Requirement R3 or R4 shall satisfy the obligations of the documented
specifications using: [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning, Same-Day Operations, Real-time Operations]
5.1. A mutually agreeable format
5.2. A mutually agreeable process for resolving data conflicts
5.3. A mutually agreeable security protocol
M5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Owner, and Distribution Provider receiving a data specification
in Requirement R3 or R4 shall make available evidence that it has satisfied the
obligations of the documented specifications. Such evidence could include, but is not

Page 2 of 10

TOP-003-4 — Operational Reliability Data

limited to, electronic or hard copies of data transmittals or attestations of receiving
entities.
C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Process
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Assessment Processes
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated reliability standard.
1.3. Data 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 responsible entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
Each Transmission Operator shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments in accordance with
Requirement R1 and Measurement M1 as well as any documents in force since
the last compliance audit.
Each Balancing Authority shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its analysis functions and
Real-time monitoring in accordance with Requirement R2 and Measurement M2
as well as any documents in force since the last compliance audit.
Each Transmission Operator shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the
Transmission Operator’s Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments in accordance with Requirement R3 and
Measurement M3.

Page 3 of 10

TOP-003-4 — Operational Reliability Data

Each Balancing Authority shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the
Balancing Authority’s analysis functions and Real-time monitoring in accordance
with Requirement R4 and Measurement M4.
Each Balancing Authority, Generator Owner, Generator Operator, Transmission
Operator, Transmission Owner, and Distribution Provider receiving a data
specification in Requirement R3 or R4 shall retain evidence for the most recent
90-calendar days that it has satisfied the obligations of the documented
specifications in accordance with Requirement R5 and Measurement M5.
If a responsible entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved or the time
period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.

Page 4 of 10

TOP-003-4 — Operational Reliability Data

Table of Compliance Elements
R#

R1

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Transmission
Operator did not
include one of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include three of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include four of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.
OR,
The Transmission
Operator did not have
a documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

Page 5 of 10

TOP-003-4 — Operational Reliability Data
R#

R2

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Balancing
Authority did not
include one of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include two of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include three of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include four of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.
OR,
The Balancing
Authority did not
have a documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

For the Requirement R3 and R4 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to
the left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity
has just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R3

Operations
Planning

Low

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

Page 6 of 10

TOP-003-4 — Operational Reliability Data
R#

R4

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to two
entities, or more than
5% and less than or
equal to10% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to three
entities, or more than
10% and less than or
equal to 15% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Balancing
Authority did not
distribute its data
specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to two
entities, or more than
5% and less than or
equal to 10% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to three
entities, or more than
10% and less than or
equal to 15% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

Page 7 of 10

TOP-003-4 — Operational Reliability Data
R#

R5

Time Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

Violation Severity Levels

VRF

Medium

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible
entity receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet one of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet two of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet three of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
did not satisfy the
obligations of the
documented
specifications for
data.

Page 8 of 10

TOP-003-4 — Guidelines and Technical Basis

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

0

April 1, 2005

0

August 8, 2005

Action

Effective Date
Removed “Proposed” from Effective
Date
Modified R1.2
Modified M1

1

Change Tracking

New
Errata
Revised

Replaced Levels of Non-compliance
with the Feb 28, BOT approved
Violation Severity Levels (VSLs)
1

October 17, 2008

Adopted by NERC Board of Trustees

1

March 17, 2011

Order issued by FERC approving TOP003-1 (approval effective 5/23/11)

2

May 6, 2012

Revised under Project 2007-03

Revised

2

May 9, 2012

Adopted by Board of Trustees

Revised

3

April 2014

Changes pursuant to Project 2014-03

Revised

3

November 13, 2014 Adopted by Board of Trustees

3

November 19, 2015 FERC approved TOP-003-3. Docket No.
RM15-16-000, Order No. 817
Adopted by NERC Board of Trustees
February 6, 2020

4

Revisions under
Project 2014-03

Revisions under
Project 2017-07

Page 9 of 10

TOP-003-4 — Guidelines and Technical Basis

Guidelines and Technical Basis
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 Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to
result in an appropriate level of situational awareness. Some examples include: 1) analyzing
phase angles which may result in the implementation of an Operating Plan to adjust generation
or curtail transactions so that a Transmission facility may be returned to service, or 2)
evaluating the impact of a modified Contingency resulting from the status change of a Special
Protection Scheme from enabled/in-service to disabled/out-of-service.
Rationale for R1:
Changes to proposed Requirement R1, Part 1.1 are in response to issues raised in NOPR
paragraph 67 on the need for obtaining non-BES and external network data necessary for the
Transmission Operator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2 is in response to NOPR paragraph 78 on relay data. The
language has been moved from approved PRC-001-1.
Corresponding changes have been made to Requirement R2 for the Balancing Authority and to
proposed IRO-010-2, Requirement R1 for the Reliability Coordinator.
Rationale for R5:
Proposed Requirement R5, Part 5.3 is in response to NOPR paragraph 92 where concerns were
raised about data exchange through secured networks.

Page 10 of 10

Exhibit A-7
Proposed Reliability Standard TOP-003-4
Redline to Last Approved (TOP-003-3)

RELIABILITY | RESILIENCE | SECURITY

Standard TOP-003-3 4 — Operational Reliability Data
A. Introduction
1.

Title: Operational Reliability Data

2.

Number: TOP-003-43

3.

Purpose: To ensure that the Transmission Operator and Balancing Authority have
data needed to fulfill their operational and planning responsibilities.

4.

Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Generator Owner
4.4. Generator Operator
4.5. Load-Serving Entity
4.6.4.5.

Transmission Owner

4.7.4.6.

Distribution Provider

5.

Effective Date: See Implementation Plan.

6.

Background:
See Project 2014-03 project page.

B. Requirements and Measures
R1. Each Transmission Operator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include, but not be limited to:
[Violation Risk Factor: Low] [Time Horizon: Operations Planning]
1.1.

A list of data and information needed by the Transmission Operator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data as
deemed necessary by the Transmission Operator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

M1. Each Transmission Operator shall make available its dated, current, in force
documented specification for data.

Page 1 of 11

Standard TOP-003-3 4 — Operational Reliability Data
R2.

Each Balancing Authority shall maintain a documented specification for the data
necessary for it to perform its analysis functions and Real-time monitoring. The data
specification shall include, but not be limited to: [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]
2.1.

A list of data and information needed by the Balancing Authority to support
its analysis functions and Real-time monitoring.

2.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

2.3.

A periodicity for providing data.

2.4.

The deadline by which the respondent is to provide the indicated data.

M2. Each Balancing Authority shall make available its dated, current, in force documented
specification for data.
R3. Each Transmission Operator shall distribute its data specification to entities that have
data required by the Transmission Operator’s Operational Planning Analyses, Realtime monitoring, and Real-time Assessment. [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]
M3. Each Transmission Operator shall make available evidence that it has distributed its
data specification to entities that have data required by the Transmission Operator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments.
Such evidence could include but is not limited to web postings with an electronic
notice of the posting, dated operator logs, voice recordings, postal receipts showing
the recipient, date and contents, or e-mail records.
R4. Each Balancing Authority shall distribute its data specification to entities that have
data required by the Balancing Authority’s analysis functions and Real-time
monitoring. [Violation Risk Factor: Low] [Time Horizon: Operations Planning]
M4. Each Balancing Authority shall make available evidence that it has distributed its data
specification to entities that have data required by the Balancing Authority’s analysis
functions and Real-time monitoring. Such evidence could include but is not limited to
web postings with an electronic notice of the posting, dated operator logs, voice
recordings, postal receipts showing the recipient, or e-mail records.
R5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R3 or R4 shall satisfy the obligations of
the documented specifications using: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning, Same-Day Operations, Real-time Operations]
5.1. A mutually agreeable format
5.2. A mutually agreeable process for resolving data conflicts
5.3. A mutually agreeable security protocol

Page 2 of 11

Standard TOP-003-3 4 — Operational Reliability Data
M5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R3 or R4 shall make available evidence
that it has satisfied the obligations of the documented specifications. Such evidence
could include, but is not limited to, electronic or hard copies of data transmittals or
attestations of receiving entities.
C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Process
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Assessment Processes
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated reliability standard.
1.3. Data 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 responsible entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
Each Transmission Operator shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments in accordance with
Requirement R1 and Measurement M1 as well as any documents in force since
the last compliance audit.
Each Balancing Authority shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its analysis functions and
Real-time monitoring in accordance with Requirement R2 and Measurement M2
as well as any documents in force since the last compliance audit.
Each Transmission Operator shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the

Page 3 of 11

Standard TOP-003-3 4 — Operational Reliability Data
Transmission Operator’s Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments in accordance with Requirement R3 and
Measurement M3.
Each Balancing Authority shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the
Balancing Authority’s analysis functions and Real-time monitoring in accordance
with Requirement R4 and Measurement M4.
Each Balancing Authority, Generator Owner, Generator Operator, Load-Serving
Entity, Transmission Operator, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R3 or R4 shall retain evidence for
the most recent 90-calendar days that it has satisfied the obligations of the
documented specifications in accordance with Requirement R5 and
Measurement M5.
If a responsible entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved or the time
period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.

Page 4 of 11

Standard TOP-003-3 4 — Operational Reliability Data
Table of Compliance Elements
R#

R1

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Transmission
Operator did not
include one of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include three of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include four of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.
OR,
The Transmission
Operator did not have
a documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

Page 5 of 11

Standard TOP-003-3 4 — Operational Reliability Data
R#

R2

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Balancing
Authority did not
include one of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include two of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include three of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include four of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.
OR,
The Balancing
Authority did not
have a documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

For the Requirement R3 and R4 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to
the left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity
has just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R3

Operations
Planning

Low

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

Page 6 of 11

Standard TOP-003-3 4 — Operational Reliability Data
R#

R4

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to two
entities, or more than
5% and less than or
equal to10% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to three
entities, or more than
10% and less than or
equal to 15% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Balancing
Authority did not
distribute its data
specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to two
entities, or more than
5% and less than or
equal to 10% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to three
entities, or more than
10% and less than or
equal to 15% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

Page 7 of 11

Standard TOP-003-3 4 — Operational Reliability Data
R#

R5

Time Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

Violation Severity Levels

VRF

Medium

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible
entity receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet one of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet two of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet three of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
did not satisfy the
obligations of the
documented
specifications for
data.

Page 8 of 11

Standard TOP-003-3 4 — Guidelines and Technical Basis
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

0

April 1, 2005

0

August 8, 2005

Action
Effective Date
Removed “Proposed” from Effective
Date
Modified R1.2
Modified M1

1

Change Tracking
New
Errata
Revised

Replaced Levels of Non-compliance
with the Feb 28, BOT approved
Violation Severity Levels (VSLs)
1

October 17, 2008

Adopted by NERC Board of Trustees

1

March 17, 2011

Order issued by FERC approving TOP003-1 (approval effective 5/23/11)

2

May 6, 2012

Revised under Project 2007-03

Revised

2

May 9, 2012

Adopted by Board of Trustees

Revised

3

April 2014

Changes pursuant to Project 2014-03

Revised

3

November 13, 2014 Adopted by Board of Trustees

3

November 19, 2015 FERC approved TOP-003-3. Docket No.
RM15-16-000, Order No. 817
Adopted by NERC Board of Trustees
February 6, 2020

4

Revisions under
Project 2014-03

Revisions under
Project 2017-07

Page 9 of 11

Standard TOP-003-3 4 — Guidelines and Technical Basis

Page 10 of 11

Standard TOP-003-3 4 — Guidelines and Technical Basis
Guidelines and Technical Basis
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 Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to
result in an appropriate level of situational awareness. Some examples include: 1) analyzing
phase angles which may result in the implementation of an Operating Plan to adjust generation
or curtail transactions so that a Transmission facility may be returned to service, or 2)
evaluating the impact of a modified Contingency resulting from the status change of a Special
Protection Scheme from enabled/in-service to disabled/out-of-service.
Rationale for R1:
Changes to proposed Requirement R1, Part 1.1 are in response to issues raised in NOPR
paragraph 67 on the need for obtaining non-BES and external network data necessary for the
Transmission Operator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2 is in response to NOPR paragraph 78 on relay data. The
language has been moved from approved PRC-001-1.
Corresponding changes have been made to Requirement R2 for the Balancing Authority and to
proposed IRO-010-2, Requirement R1 for the Reliability Coordinator.
Rationale for R5:
Proposed Requirement R5, Part 5.3 is in response to NOPR paragraph 92 where concerns were
raised about data exchange through secured networks.

Page 11 of 11

Exhibit B
Implementation Plan

RELIABILITY | RESILIENCE | SECURITY

Implementation Plan

Project 2017-07 Standards Alignment with Registration
Applicable Standards
•

FAC-002-3 – Facility Interconnection Studies

•

IRO-010-3 – Reliability Coordinator Data Specification and Collection

•

MOD-031-3 – Demand and Energy Data

•

MOD-033-2 – Steady-State and Dynamic System Model Validation

•

NUC-001-4 – Nuclear Plant Interface Coordination

•

PRC-006-4 – Automatic Underfrequency Load Shedding

•

TOP-003-4 – Operational Reliability Data

Requested Retirements
•

FAC-002-2 – Facility Interconnection Studies

•

IRO-010-2 – Reliability Coordinator Data Specification and Collection

•

MOD-031-2 – Demand and Energy Data

•

MOD-033-1 – Steady-State and Dynamic System Model Validation

•

NUC-001-3 – Nuclear Plant Interface Coordination

•

PRC-006-3 – Automatic Underfrequency Load Shedding

•

TOP-003-3 – Operational Reliability Data

Applicable Entities
See subject standards.
Background
On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North
American Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) initiative in Docket
No. RR15-4-000. FERC approved the removal of two functional categories, Purchasing-Selling Entity
(PSE) and Interchange Authority (IA), from the NERC Compliance Registry due to the commercial
nature of these categories posing little or no risk to the reliability of the bulk power system. FERC
also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently approved
on compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria.

RELIABILITY | RESILIENCE | SECURITY

Several projects have addressed standards impacted by the RBR initiative since FERC approval;
however, there remain some Reliability Standards that require minor revisions so that they align
with the post-RBR registration impacts.
Project 2017-07 Standards Alignment with Registration formally addressed the remaining edits to
the Reliability Standards that are needed to align the existing standards with the RBR
initiatives. The edits include updates to the FAC, IRO, MOD, NUC, and TOP family of standards.
References to Load-Serving Entity (LSEs) were removed or replaced by the appropriate NERC
Registered Entity. PRC-006 was updated to include the more-limited UFLS-only Distribution
Provider (DP) to the Applicability Section. A majority of the edits simply removed deregistered
functional entities and their applicable requirements/references.
Effective Date
Reliability Standards FAC-002-3, IRO-010-3, MOD-031-3, MOD-033-2, NUC-001-4, PRC-006-4, and TOP003-4
Where approval by an applicable governmental authority is required, the standard shall become
effective on the first day of the first calendar quarter that is three (3) months after the effective date of
the applicable governmental authority’s order approving the standard, or as otherwise provided for by
the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is three (3) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Retirement Date
Reliability Standards FAC-002-2, IRO-010-2, MOD-031-2, MOD-033-1, NUC-001-3, PRC-006-

3, and TOP-003-3

The Reliability Standard shall be retired immediately prior to the effective date of the revised standard
in the particular jurisdiction in which the revised standard is becoming effective.

Implementation Plan
Project 2017-07 Standards Alignment with Registration | January 2020

2

Exhibit C
Order No. 672 Criteria

RELIABILITY | RESILIENCE | SECURITY

Exhibit C — Order No. 672 Criteria
Order No. 672 Criteria
In Order No. 672, 1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standards have met or exceeded the criteria.
1.

Proposed Reliability Standards must be designed to achieve a specified reliability goal
and must contain a technically sound means to achieve that goal. 2
The proposed Reliability Standards revise the currently effective versions to align the

standards with registration changes approved by the Commission in 2015. In the proposed
Reliability Standards, references to entities that are no longer registered by NERC are removed.
Proposed Reliability Standard PRC-006-3 adds the Underfrequency Load Shedding (“UFLS”)Only Distribution Provider as an applicable entity. In addition, revisions are proposed to ensure
consistent use of the term Planning Coordinator across the body of NERC Reliability Standards.
No substantive revisions are made to the underlying requirements.

1

Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, 114 FERC ¶ 61,104,
order on reh’g, Order No. 672-A, 114 FERC ¶ 61,328 (2006) [hereinafter Order No. 672].
2
See Order No. 672, supra note 1, at P 321 (“The proposed Reliability Standard must address a reliability
concern that falls within the requirements of section 215 of the FPA. That is, it must provide for the reliable operation
of Bulk-Power System facilities. It may not extend beyond reliable operation of such facilities or apply to other
facilities. Such facilities include all those necessary for operating an interconnected electric energy transmission
network, or any portion of that network, including control systems. The proposed Reliability Standard may apply to
any design of planned additions or modifications of such facilities that is necessary to provide for reliable operation.
It may also apply to Cybersecurity protection.”).
See Order No. 672, supra note 1, at P 324 (“The proposed Reliability Standard must be designed to achieve
a specified reliability goal and must contain a technically sound means to achieve this goal. Although any person may
propose a topic for a Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability Standard
should be developed initially by persons within the electric power industry and community with a high level of
technical expertise and be based on sound technical and engineering criteria. It should be based on actual data and
lessons learned from past operating incidents, where appropriate. The process for ERO approval of a proposed
Reliability Standard should be fair and open to all interested persons.”).

2.

Proposed Reliability Standards must be applicable only to users, owners, and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply. 3
The proposed Reliability Standards are clear and unambiguous as to what is required and

who is required to comply, in accordance with Order No. 672. The revisions reflected in the
proposed standards would promote alignment and consistency across NERC Reliability Standards
and the NERC registration criteria and would reduce the potential for confusion regarding which
entities are responsible for compliance with the standards.
3.

A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 4
The Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for the

proposed Reliability Standards are substantively unchanged from currently effective versions of
the Reliability Standards, reflecting only those revisions necessary to effectuate the proposed
alignment revisions. They continue to comport with NERC and Commission guidelines related to
their assignment. The assignment of the severity level for each VSL is consistent with the
corresponding requirement and the VSLs should ensure uniformity and consistency in the
determination of penalties. The VSLs do not use any ambiguous terminology, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
For these reasons, the proposed Reliability Standards include clear and understandable
consequences in accordance with Order No. 672.

3

See Order No. 672, supra note 1, at P 322 (“The proposed Reliability Standard may impose a requirement on
any user, owner, or operator of such facilities, but not on others.”).
See Order No. 672, supra note 1, at P 325 (“The proposed Reliability Standard should be clear and
unambiguous regarding what is required and who is required to comply. Users, owners, and operators of the BulkPower System must know what they are required to do to maintain reliability.”).
4
See Order No. 672, supra note 1, at P 326 (“The possible consequences, including range of possible penalties,
for violating a proposed Reliability Standard should be clear and understandable by those who must comply.”).

2

4.

A proposed Reliability Standard must identify clear and objective criteria or
measures for compliance, so that it can be enforced in a consistent and nonpreferential manner. 5
The proposed Reliability Standards contain measures that support each requirement by

clearly identifying what is required and how the requirement will be enforced. These measures
help provide clarity regarding how the requirements will be enforced and help ensure that the
requirements will be enforced in a clear, consistent, and non-preferential manner and without
prejudice to any party. The measures are substantively unchanged from currently enforceable
versions of the Reliability Standards, reflecting only those revisions necessary to effectuate the
proposed alignment revisions.
5.

Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently, but do not necessarily have to reflect “best practices” without regard to
implementation cost or historical regional infrastructure design. 6
The proposed Reliability Standards achieve their reliability goals effectively and efficiently

in accordance with Order No. 672. The proposed Reliability Standards clarify which entities
remain applicable to each standard following the registration changes previously approved by the
Commission in 2015. NERC does not propose any substantive revisions to the underlying standard
requirements.
6.

Proposed Reliability Standards cannot be “lowest common denominator,” i.e., cannot
reflect a compromise that does not adequately protect Bulk-Power System reliability.
Proposed Reliability Standards can consider costs to implement for smaller entities,
but not at consequences of less than excellence in operating system reliability. 7

5
See Order No. 672, supra note 1, at P 327 (“There should be a clear criterion or measure of whether an entity
is in compliance with a proposed Reliability Standard. It should contain or be accompanied by an objective measure
of compliance so that it can be enforced and so that enforcement can be applied in a consistent and non-preferential
manner.”).
6
See Order No. 672, supra note 1, at P 328 (“The proposed Reliability Standard does not necessarily have to
reflect the optimal method, or ‘best practice,’ for achieving its reliability goal without regard to implementation cost
or historical regional infrastructure design. It should however achieve its reliability goal effectively and efficiently.”).
7
See Order No. 672, supra note 1, at P 329 (“The proposed Reliability Standard must not simply reflect a
compromise in the ERO’s Reliability Standard development process based on the least effective North American
practice—the so-called ‘lowest common denominator’—if such practice does not adequately protect Bulk-Power

3

The proposed Reliability Standards do not reflect a “lowest common denominator”
approach. The proposed Reliability Standards clarify which entities must comply with the
standards following registration changes previously approved by the Commission in 2015. NERC
does not propose any substantive revisions to the underlying standard requirements.
7.

Proposed Reliability Standards must be designed to apply throughout North America
to the maximum extent achievable with a single Reliability Standard while not
favoring one geographic area or regional model. It should take into account regional
variations in the organization and corporate structures of transmission owners and
operators, variations in generation fuel type and ownership patterns, and regional
variations in market design if these affect the proposed Reliability Standard. 8
The proposed Reliability Standards continue to apply consistently throughout North

America and do not favor one geographic area or regional model. The proposed Reliability
Standards clarify which entities must comply with the standards following registration changes
previously approved by the Commission in 2015. NERC does not propose any substantive
revisions to the underlying standard requirements.

System reliability. Although the Commission will give due weight to the technical expertise of the ERO, we will not
hesitate to remand a proposed Reliability Standard if we are convinced it is not adequate to protect reliability.”).
See Order No. 672, supra note 1, at P 330 (“A proposed Reliability Standard may take into account the size
of the entity that must comply with the Reliability Standard and the cost to those entities of implementing the proposed
Reliability Standard. However, the ERO should not propose a ‘lowest common denominator’ Reliability Standard that
would achieve less than excellence in operating system reliability solely to protect against reasonable expenses for
supporting this vital national infrastructure. For example, a small owner or operator of the Bulk-Power System must
bear the cost of complying with each Reliability Standard that applies to it.”).
8
See Order No. 672, supra note 1, at P 331 (“A proposed Reliability Standard should be designed to apply
throughout the interconnected North American Bulk-Power System, to the maximum extent this is achievable with a
single Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or regional
model but should take into account geographic variations in grid characteristics, terrain, weather, and other such
factors; it should also take into account regional variations in the organizational and corporate structures of
transmission owners and operators, variations in generation fuel type and ownership patterns, and regional variations
in market design if these affect the proposed Reliability Standard.”).

4

8.

Proposed Reliability Standards should cause no undue negative effect on competition
or restriction of the grid beyond any restriction necessary for reliability. 9
The proposed Reliability Standards have no undue negative effect on competition and do

not unreasonably restrict the available transmission capacity or limit the use of the BPS in a
preferential manner. The proposed standards continue to require the same performance by each of
the applicable entities, which have been aligned to reflect registration changes previously approved
by the Commission in 2015.
9.

The implementation time for the proposed Reliability Standard is reasonable. 10
The proposed effective date for the proposed Reliability Standards is just and reasonable

and appropriately balances the urgency in the need to implement the standards against the
reasonableness of the time allowed for those who must comply to develop necessary procedures,
software, facilities, staffing, or other relevant capability. The proposed implementation plan
provides that the proposed Reliability Standards would become effective on the first day of the
first calendar quarter that is three months after applicable regulatory approval. The currently
effective versions of the standards would be retired immediately prior to the effective date of the
revised Reliability Standards. This implementation timeline reflects consideration that entities may
need time to update their internal systems and documentation to reflect the new Reliability

9

See Order No. 672, supra note 1, at P 332 (“As directed by section 215 of the FPA, FERC itself will give
special attention to the effect of a proposed Reliability Standard on competition. The ERO should attempt to develop
a proposed Reliability Standard that has no undue negative effect on competition. Among other possible
considerations, a proposed Reliability Standard should not unreasonably restrict available transmission capability on
the Bulk-Power System beyond any restriction necessary for reliability and should not limit use of the Bulk-Power
System in an unduly preferential manner. It should not create an undue advantage for one competitor over another.”).
10
See Order No. 672, supra note 1, at P 333 (“In considering whether a proposed Reliability Standard is just
and reasonable, the Commission will consider also the timetable for implementation of the new requirements,
including how the proposal balances any urgency in the need to implement it against the reasonableness of the time
allowed for those who must comply to develop the necessary procedures, software, facilities, staffing or other relevant
capability.”).

5

Standard version numbers. The proposed implementation plan is attached as Exhibit B to this
petition.
10.

The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 11
The proposed Reliability Standards were developed in accordance with NERC’s

Commission-approved, ANSI-accredited processes for developing and approving Reliability
Standards. Exhibit E includes a summary of the Reliability Standard development proceedings,
and details the processes followed to develop the proposed Reliability Standards. These processes
included, among other things, comment periods, pre-ballot review periods, and balloting periods.
Additionally, all meetings of the standard drafting team were properly noticed and open to the
public.
11.

NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.12
NERC has identified no competing public interests regarding the request for approval of

this proposed Reliability Standards. No comments were received that indicated that one or more
of the proposed Reliability Standards conflicts with other vital public interests.

11

See Order No. 672, supra note 1, at P 334 (“Further, in considering whether a proposed Reliability Standard
meets the legal standard of review, we will entertain comments about whether the ERO implemented its Commissionapproved Reliability Standard development process for the development of the particular proposed Reliability
Standard in a proper manner, especially whether the process was open and fair. However, we caution that we will not
be sympathetic to arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s
Reliability Standard development process if it is conducted in good faith in accordance with the procedures approved
by the Commission.”).
12
See Order No. 672, supra note 1, at P 335 (“Finally, we understand that at times development of a proposed
Reliability Standard may require that a particular reliability goal must be balanced against other vital public interests,
such as environmental, social and other goals. We expect the ERO to explain any such balancing in its application for
approval of a proposed Reliability Standard.”).

6

12.

Proposed Reliability Standards must consider any other appropriate factors. 13
No other negative factors relevant to whether the proposed Reliability Standards are just

and reasonable were identified.

13

See Order No. 672, supra note 1, at P 323 (“In considering whether a proposed Reliability Standard is just
and reasonable, we will consider the following general factors, as well as other factors that are appropriate for the
particular Reliability Standard proposed.”).

7

Exhibit D
Analysis of Violation Risk Factors and Violation Severity Levels

RELIABILITY | RESILIENCE | SECURITY

Exhibit D-1
Analysis of Violation Risk Factors and Violation Severity Levels
Proposed Reliability Standard FAC-002-3

RELIABILITY | RESILIENCE | SECURITY

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, FAC-002-3. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for FAC-002-3, Requirement R1
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R1
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF Justification for FAC-002-3, Requirement R2
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R2
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF Justification for FAC-002-3, Requirement R3
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R3
This justification is provided on the following page.
VRF Justification for FAC-002-3, Requirement R4
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R4
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF Justification for FAC-002-3, Requirement R5
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R5
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

VSLs for FAC-002-3, Requirement R3

Lower

Moderate

High

Severe

The Transmission Owner or
Distribution Provider seeking to
interconnect new transmission
Facilities or electricity end-user
Facilities, or to materially modify
existing interconnections of
transmission Facilities or
electricity end-user Facilities,
coordinated and cooperated on
studies with its Transmission
Planner or Planning Coordinator,
but failed to provide data
necessary to perform studies as
described in one of the Parts
(R1, 1.1-1.4).

The Transmission Owner, or
Distribution Provider Entity
seeking to interconnect new
transmission Facilities or
electricity end-user Facilities, or
to materially modify existing
interconnections of transmission
Facilities or electricity end-user
Facilities, coordinated and
cooperated on studies with its
Transmission Planner or
Planning Coordinator, but failed
to provide data necessary to
perform studies as described in
two of the Parts (R1, 1.1-1.4).

The Transmission Owner or
Distribution Provider Entity
seeking to interconnect new
transmission Facilities or
electricity end-user Facilities, or
to materially modify existing
interconnections of transmission
Facilities or electricity end-user
Facilities, coordinated and
cooperated on studies with its
Transmission Planner or
Planning Coordinator, but failed
to provide data necessary to
perform studies as described in
three of the Parts (R1, 1.1-1.4).

The Transmission Owner, or
Distribution Provider Entity
seeking to interconnect new
transmission Facilities or
electricity end-user Facilities, or
to materially modify existing
interconnections of transmission
Facilities or electricity end-user
Facilities, failed to coordinate
and cooperate on studies with
its Transmission Planner or
Planning Coordinator.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

6

Exhibit D-2
Analysis of Violation Risk Factors and Violation Severity Levels
Proposed Reliability Standard IRO-010-3

RELIABILITY | RESILIENCE | SECURITY

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, IRO-010-3. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for IRO-010-3, Requirement R1
The VRF did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VSL Justification for IRO-010-3, Requirement R1
The VSL did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VRF Justification for IRO-010-3, Requirement R2
The VRF did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VSL Justification for IRO-010-3, Requirement R2
The VSL did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VRF Justification for IRO-010-3, Requirement R3
The VRF did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VSL Justification for IRO-010-3, Requirement R3
The VSL did not change from the previously FERC approved IRO-010-2 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

Exhibit D-3
Analysis of Violation Risk Factors and Violation Severity Levels
Proposed Reliability Standard MOD-031-3

RELIABILITY | RESILIENCE | SECURITY

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, MOD-031-3. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for MOD-031-3, Requirement R1
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R1
The VSL did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VRF Justification for MOD-031-3, Requirement R2
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R2
The VSL did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VRF Justification for MOD-031-3, Requirement R3
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R3
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VRF Justification for MOD-031-3, Requirement R4
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R4
The VSL did not change from the previously FERC approved MOD-031-2 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

Exhibit D-4
Analysis of Violation Risk Factors and Violation Severity Levels
Proposed Reliability Standard MOD-033-2

RELIABILITY | RESILIENCE | SECURITY

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, MOD-033-2. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for MOD-033-2, Requirement R1
The VRF did not change from the previously FERC approved MOD-033-1 Reliability Standard.
VSL Justification for F MOD-033-2, Requirement R1
The VSL did not change from the previously FERC approved MOD-033-1 Reliability Standard.
VRF Justification for MOD-033-2, Requirement R2
The VRF did not change from the previously FERC approved MOD-033-1 Reliability Standard.
VSL Justification for MOD-033-2, Requirement R2
The VSL did not change from the previously FERC approved MOD-033-1 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

Exhibit D-5
Analysis of Violation Risk Factors and Violation Severity Levels
Proposed Reliability Standard NUC-001-4

RELIABILITY | RESILIENCE | SECURITY

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, NUC-001-4. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for NUC-001-4, Requirement R1
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.

VSL Justification for NUC-001-4, Requirement R1
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R2
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R2
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R3
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R3
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R4
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R4
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R5
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R5
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

VRF Justification for NUC-001-4, Requirement R6
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R6
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R7
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R7
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R8
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R8
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R9
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R9
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

6

Exhibit D-6
Analysis of Violation Risk Factors and Violation Severity Levels
Proposed Reliability Standard PRC-006-4

RELIABILITY | RESILIENCE | SECURITY

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, PRC-006-4. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for PRC-006-4, Requirement R1
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R1
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R2
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R2
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R3
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R3
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R4
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R4
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R5
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R5
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

VRF Justification for PRC-006-4, Requirement R6
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R6
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R7
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R7
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R8
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R8
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R9
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R9
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R10
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R10
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R11
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

6

VSL Justification for PRC-006-4, Requirement R11
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R12
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R12
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R13
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R13
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R14
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R14
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R15
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R15
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

7

Exhibit D-7
Analysis of Violation Risk Factors and Violation Severity Levels
Proposed Reliability Standard TOP-003-4

RELIABILITY | RESILIENCE | SECURITY

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, TOP-003-4. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for TOP-003-4, Requirement R1
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R1
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R2
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R2
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R3
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R3
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R4
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R4
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R5
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R5
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

Exhibit E
Summary of Development and Complete Record of Development

RELIABILITY | RESILIENCE | SECURITY

Summary of Development History
The following is a summary of the development record for the proposed Reliability
Standards developed under Project 2017-07 Standards Alignment with Registration.
I.

Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to give “due

weight” to the technical expertise of the ERO. 1 The technical expertise of the ERO is derived from
the standard drafting team (“SDT”) selected to lead each project in accordance with Section 4.3 of
the NERC Standard Processes Manual, Appendix 3A to the NERC Rules of Procedure. 2 For this
project, the SDT consisted of industry experts, all with a diverse set of experiences. A roster of the
Project 2017-07 Standards Alignment with Registration SDT members is included in Exhibit F.
II.

Standard Development History
A. Standard Authorization Request Development
On July 19, 2017, the Standards Committee authorized: (i) posting the general Standards

Alignment with Registration Standard Authorization Request (“SAR”) for a 30-day formal
comment period; (ii) posting a SAR to revise MOD-032-1 for a 30-day formal comment period;
and (iii) soliciting nominations for a SAR drafting team to consider both SARs and develop a
combined SAR. 3 The SARs were posted for comment from August 1, 2017 through August 30,
2017 and the SAR drafting team nominations were open from August 1, 2017 through August 14,
2017. The Standards Alignment with Registration SAR received 19 sets of responses, including

1

Section 215(d)(2) of the Federal Power Act; 16 U.S.C. § 824(d)(2) (2018).
The NERC Standard Processes Manual is available at
https://www.nerc.com/FilingsOrders/us/RuleOfProcedureDL/SPM_Clean_Mar2019.pdf.
3
NERC, Agenda — Standards Committee Meeting, Agenda Item 11 (Project 2017-07 Standards Alignment
with Registration),
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/SC%20Agenda%20Package_July1920
17.pdf.
2

1

comments from approximately 64 different people from approximately 52 companies,
representing 10 of the Industry segments. 4 The MOD-032-1 SAR received 18 sets of responses,
including comments from approximately 63 different people from approximately 51 companies,
representing all 10 industry segments. 5
The Standards Committee appointed the SAR SDT on October 18, 2017. 6 The SDT
combined the initial two SARs into a single project and posted a revised SAR from December 11,
2017 through January 9, 2018. There were 16 sets of responses, including comments from
approximately 67 different people from approximately 51 companies, representing all 10 of the
Industry Segments. 7 Based on those comments, the SDT posted a final SAR including
clarifications in project scope and considering synergies with other ongoing standards projects.
The final SAR was posted for a 30-day formal comment period from February 1, 2018 through
March 2, 2018. There were 18 sets of responses, including comments from approximately 76
different people from approximately 62 companies, representing all 10 of the Industry Segments. 8

4

NERC, Consideration of Comments — 2017-07 Standards Alignment with Registration SAR,
https://www.nerc.com/pa/Stand/Project201707StandardsAlignmentwithRegistration/2017_07_Consideration_of_Co
mments_1211017.pdf.
5
NERC, Consideration of Comments — 2017-07 Standards Alignment with Registration SAR — MOD-0321, https://www.nerc.com/pa/Stand/Project201707StandardsAlignmentwithRegistration/201707_RAW_MOD032_SAR_083117.pdf.
6
NERC, Minutes — Standards Committee Conference Call, Agenda Item 8 (Project 2017-07 Standards
Alignment with Registration ), October 18, 2017,
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/Standards%20Committee%20Meeting
%20Minutes%20-%20Approved_October_18_2017.pdf.
7
NERC, Consideration of Comments — 2017-07 Standards Alignment with Registration — Standards
Authorization Request, https://www.nerc.com/pa/Stand/Project201707StandardsAlignmentwithRegistration/201707_Consideration_of_Comments_SAR2Feb2018.pdf.
8
NERC, Consideration of Comments — 2017-07 Standards Alignment with Registration — Standards
Authorization Request,
https://www.nerc.com/pa/Stand/Project201707StandardsAlignmentwithRegistration/Project%20%20201707_Consideration_of_Comments_030518.pdf.

2

The Standards Committee accepted the final SAR on April 18, 2018, authorized the
proposed Reliability Standards revisions, and authorized posting for nominations to the Project
2017-07 SDT. 9 The nominations were open from May 1, 2018 through May 14, 2018.
B. First Posting – Formal Comment Period and Initial Ballot
An initial draft of the seven proposed Reliability Standards (FAC-002-3, IRO-010-3,
MOD-031-3, MOD-033-2, NUC-001-4, PRC-006-4, and TOP-003-4), the implementation plan,
and the supporting materials were posted for a 45-day formal comment period from October 29,
2019 through December 12, 2019. There were 32 sets of responses, including comments from
approximately 75 different people from approximately 61 companies, representing 10 of the
Industry Segments. 10 An initial ballot was open for the final ten days of the comment period from
December 3, 2019 through December 12, 2019. The table below summarizes the results of the
initial ballot and nonbinding poll. 11
Ballot

Non-binding Poll

Quorum / Approval

Quorum / Supportive Opinions

FAC-002-3

88.76% / 99.69%

86.99% / 99.44%

IRO-010-3

89.02% / 99.36%

87.6% / 99.43%

MOD-031-3

89.02% / 99.69%

87.19% / 99.43%

MOD-033-2

88.98% / 99.69%

86.78% / 99.43%

NUC-001-4

89.96% / 99.59%

87.67% / 99.31%

9

NERC , Minutes — Standards Committee Conference Call, Agenda Item 5 (Project 2017-07 Standards
Alignment with Registration), April 18, 2018,
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/Standards%20Committee%20Meeting
%20Minutes%20-%20Approved%20June%2013,%202018.pdf.
10
NERC, Consideration of Comments,
https://www.nerc.com/pa/Stand/Project201707StandardsAlignmentwithRegistration/201707%20Consideration%20of%20Comments_January2020.pdf.
11
The results are posted on the project page at
https://www.nerc.com/pa/Stand/Pages/Project201707StandardsAlignmentwithRegistration.aspx.

3

Ballot

Non-binding Poll

Quorum / Approval

Quorum / Supportive Opinions

PRC-006-4

89.06% / 99.38%

86.36% / 98.84%

TOP-003-4

88.72% / 99.69%

86.48% / 99.43%

Implementation Plan

87.89% / 99.68%

C. Final Ballot
The proposed Reliability Standards were posted for a 10-day final ballot period from
January 14, 2020 through January 23, 2020. The results are summarized in the table below. 12
Name

Quorum / Approval

FAC-002-3

89.53% / 99.69%

IRO-010-3

89.8% / 99.69%

MOD-031-3

89.8% / 99.69%

MOD-033-2

89.76% / 99.69%

NUC-001-4

90.83% / 99.6%

PRC-006-4

89.84% / 99.38%

TOP-003-4

89.88% / 99.69%

Implementation Plan

88.67% / 99.69%

12

The results are posted on the project page at
https://www.nerc.com/pa/Stand/Pages/Project201707StandardsAlignmentwithRegistration.aspx.

4

D. Board of Trustees Adoption
On February 6, 2020, the NERC Board of Trustees adopted proposed Reliability Standards
FAC-002-3, IRO-010-3, MOD-031-3, MOD-033-2, NUC-001-4, PRC-006-4, and TOP-003-4,
and approved the implementation plan and the associated VRFs and VSLs 13

13

NERC, Agenda — Board of Trustees, Agenda Item 7a, February 6, 2020,
https://www.nerc.com/gov/bot/Agenda%20highlights%20and%20Mintues%202013/Board_Open_Meeting_Agenda
_Package_February_6_2020.pdf.

5

Complete Record of Development

6

Project 2017-07 Standards Alignment with Registration
Related Files
Status
Final ballots for Project 2017-07 Standards Alignment with Registration concluded at 8 p.m. Eastern, Thursday, January 23, 2020 for the following Standards and
ImplementationPlan:
FAC-002-3 – Facility Interconnection Studies
IRO-010-3 – Reliability Coordinator Data Specification and Collection
MOD-031-3 – Demand and Energy Data
MOD-033-2 – Steady-State and Dynamic System Model Validation
NUC-001-4 – Nuclear Plant Interface Coordination
PRC-006-4 – Automatic Underfrequency Load Shedding
TOP-003-4 – Operational Reliability Data
Implementation Plan
Background
On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North American Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) Initiative in Docket No.
RR15-4-000. FERC approved the removal of two functional categories, Purchasing-Selling Entity (PSE) and Interchange Authority (IA), from the NERC Compliance Registry due to the commercial
nature of these categories posing little or no risk to the reliability of the bulk power system.
FERC also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)-only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently
approved on compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria.
Several projects have addressed standards impacted by the RBR initiative since FERC approval; however, there remain some Reliability Standards that require minor revisions so that they align
with the post-RBR registration impacts.
Standard(s) Affected: BAL, CIP, IRO and TOP Family of Standards, MOD-032-1 – Data for Power System Modeling and Analysis, PRC-005-1.1b – Transmission and Generation Protection
System Maintenance and Testing, INT-004-3.1 – Dynamic Transfers, NUC-001-3 – Nuclear Plant Interface Coordination

Update: The following Reliability Standards were reviewed but are not being proposed for modification at this time due to the following reasons:
BAL-005-0.2b has been superseded by BAL-005-1 on January 1, 2019, which deleted the Load-Serving Entity function).
CIP-002-5.1a, CIP-003-6, CIP-003-7, CIP-004-6, CIP-005-5, CIP-005-6, CIP-006-6, CIP-007-6, CIP-008-5, CIP-009-6, CIP-010-2, and CIP-011-2 will not be revised at this time due to the
current Project 2016-02 (Modifications to CIP Standards) and the CIP Standards Efficiency Review.
FAC-010-3, FAC-011-3, and FAC-014-2 are being addressed in Project 2015-09.
INT-004-3.1 and INT-006-4 are recommended for retirement by Standard Efficiency Review Phase 1.
MOD-001-2, MOD-004-1, MOD-020-0 are recommended for retirement by Standard Efficiency Review Phase 1.
MOD-032-1 will not be revised at this time, but may come back into Project 2017-07. The work of the System Planning Impact from Distributed Energy Resource Working Group
(SPIDERWG) is ongoing at the time of the final posting for Project 2017-07. In June 2018, the NERC Planning Committee (PC) formed the SPDERWG subcommittee to address Distributed
Energy Resource (DER) impacts on the bulk power system (BPS). Currently, the subcommittee has proposed a Standard Authorization Request (SAR) for MOD-032-1 pertaining to DERs.
The SAR has recently been reviewed by the PC. At this time, the Project 2017-07 drafting team will not take any action in reference to the MOD-032 standard until the SPIDERWG has
completed their initial efforts.
PRC-005-6 will not be revised at this time due to the current Project 2019-04 (Modifications to PRC-005-6).
Purpose/Industry Need
Project 2017-7 Standards Alignment with Registration will formally address any remaining edits to the Reliability Standards that are needed to align the existing standards with the RBR initiatives.
The edits include updates to the BAL, CIP, FAC, INT, IRO, MOD, NUC, and TOP family of standards to remove the references to Purchasing-Selling Entities (PSEs) and Interchange Authorities
(IAs); references to the Load-Serving Entity (LSEs) will be removed or replaced by the appropriate NERC Registered Entity. The project will include adding Underfrequency Load Shedding (UFLS)only DPs to the Applicability Section of PRC-005 and PRC-006 per NERC registration criteria. This alignment includes three categories:
1. Modifications to existing standards where the removal of the retired function may need replacement by another function. Specifically, Reliability Standard MOD-032-1 specifies certain data
from LSEs that may need to be provided by other functional entities going forward.
2.

Modifications where the applicable entity and references may be removed. These updates may be able to follow a similar process to the Paragraph 81 initiatives where standards are
redlined and posted for industry comment and ballot. A majority of the edits would simply remove deregistered functional entities and their applicable requirements/references.
Additionally PRC-005 and PRC-006 will be updated to replace Distribution Providers (DP) with the more-limited UFLS-only DP to the Applicability Sections.

3. Initiatives that can address RBR updates through the periodic review process. This would include the INT-004-3.1 and NUC-001-3 standards. Rather than the Project 2017-07 making the
revisions the SDT could coordinate with the periodic review teams currently reviewing INT-004-3.1 and NUC-001-3 so that any changes resulting from those periodic reviews, if any, may
be proposed at the same time after completion of each periodic review.

Dra

Ac ons

Dates

Results

Final

Ballot Results

FAC-002-3

(103) FAC-002-3

(65) Clean | (66) Redline | (67) Redline to last approved
IRO-010-3
(68) Clean | (69) Redline | (70) Redline to last approved
MOD-031-3
(71) Clean | (72) Redline | (73) Redline to last approved

(104) IRO-010-3
(105) MOD-031-3
(106) MOD-033-2
(107) NUC-001-4

Considera on of
Comments

MOD-033-2
(74) Clean | (75) Redline | (76) Redline to last approved
NUC-001-4
(77) Clean | (78) Redline | (79) Redline to last approved
PRC-006-4

Final Ballot

01/14/20 - 01/23/20

(102) Info

(108) PRC-006-4
(109) TOP-003-4
(110) Implementation
Plan

Vote

(80) Clean | (81) Redline | (82) Redline to last approved
TOP-003-4
(83) Clean | (84) Redline | (85) Redline to last approved
Implementation Plan
(86) Clean | (87) Redline
Suppor ng Materials

FAC-002-3 VRF/VSL Justification
(88) Clean | (89) Redline
IRO-010-3 VRF/VSL Justification
(90) Clean | (91) Redline
MOD-031-3 VRF/VSL Justification
(92) Clean | (93) Redline
MOD-033-2 VRF/VSL Justification
(94) Clean | (95) Redline
NUC-001-4 VRF/VSL Justification
(96) Clean | (97) Redline
PRC-006-4 VRF/VSL Justification
(98) Clean | (99) Redline
TOP-003-4 VRF/VSL Justification
(100) Clean | (101) Redline

Dra 1

Ballot Results

FAC-002-3

(50) FAC-002-3

(23) Clean | (24) Redline

(51) IRO-010-3

IRO-010-3
(25) Clean | (26) Redline

(52) MOD-031-3

MOD-031-3
(27) Clean | (28) Redline

(53) MOD-033-2

MOD-033-2

(54) NUC-001-4

(29) Clean | (30) Redline

(55) PRC-006-4

NUC-001-4
(31) Clean | (32) Redline

PRC-006-4
(33) Clean | (34) Redline

TOP-003-4
(35) Clean | (36) Redline

Ini al Ballot
(49) Info

Vote

12/03/19 - 12/12/19

(56) TOP-003-4
(57) Implementation
Plan

Non-binding Poll
Results

(37) Implementation Plan

(58) FAC-002-3

(59) IRO-010-3

Suppor ng Materials
(38) Unofficial Comment Form (Word)

(60) MOD-031-3
(39) FAC-002-3 VRF/VSL Justification

(61) MOD-033-2

(40) IRO-010-3 VRF/VSL Justification
(41) MOD-031-3 VRF/VSL Justification

(62) NUC-001-4

(42) MOD-033-2 VRF/VSL Justification

(63) PRC-006-4

(43) NUC-001-4 VRF/VSL Justification

(64) TOP-003-4

(44) PRC-006-4 VRF/VSL Justification
(45) TOP-003-4 VRF/VSL Justification

Comment Period
(46) Info

10/29/19 - 12/12/19

(47) Comments

Received

Submit Comments

(48) Consideration of

Comments
Join Ballot Pools

10/29/19 - 11/27/19

Send RSAW feedback to:
RSAWfeedback@nerc.net

Dra ing Team Nomina ons

Nomination Period

Supporting Materials

(22) Info

(21) Unofficial Nomination Form (Word)

Submit Nominations

Standards Authorization Request
(17) Clean | (18) Redline
Supporting Materials

05/01/18 – 05/14/18

Comment Period
(20a) Info

Submit Comments

02/01/18 – 03/02/18

(20b) Comments (20c)Consideraton
of Comments
Received

(19) Unofficial Comment Form (Word)

Additional SAR for Standards Alignment with Registration

Comment Period

(12) Clean | (13) Redline

(15) Info

Supporting Materials

12/11/17 – 01/09/18

Submit Comments

(16a) Comments
Received

(16b)Consideraton
of Comments

(10) Comments

(11)Consideraton of

Received

Comments

(14) Unofficial Comment Form (Word)

(7) SAR for Standards Alignment with Registration

Comment Period

Supporting Materials

(9) Info

(8) Unofficial Comment Form (Word)

Submit Comments

08/01/17 – 08/30/17

(3) SAR for MOD-032-1

Comment Period

Supporting Materials

(5) Info

(4) Unofficial Comment Form (Word)

Submit Comments

SAR Drafting Team Nominations

Nomination Period

Supporting Materials

(2) Info

(1) Unofficial Nomination Form (Word)

Submit Nominations

08/01/17 – 08/30/17

( 6 ) Comments

Received

08/01/17 – 08/14/17

Unofficial Nomination Form

Project 2017-07 Standards Alignment with Registration
SAR Drafting Team
Do not use this form for submitting nominations. Use the electronic form to submit nominations by
8 p.m. Eastern, Monday, August 14, 2017. This unofficial version is provided to assist nominees in
compiling the information necessary to submit the electronic form.
Additional information about this project is available on the Project 2017-07 Standards Alignment with
Registration page. If you have questions, contact Standards Developer, Laura Anderson (via email), or at
404-446-9671.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
Previous drafting or review team experience is beneficial, but not required. A brief description of the
desired qualifications, expected commitment, and other pertinent information is included below.
Project 2017-07 Standards Alignment with Registration

The purpose of this project is focused on making the tailored Reliability Standards updates necessary to
reflect the retirement of PSEs, IAs, and LSEs (as well as all of their applicable references). This alignment
includes three categories:
1. Modifications to existing standards where the removal of the retired function may need
replacement by another function. Specifically, Reliability Standard MOD-032-1 specifies certain
data from LSEs that may need to be provided by other functional entities going forward.
2. Modifications where the applicable entity and references may be removed. These updates may be
able to follow a similar process to the Paragraph 81 initiatives where standards are redlined and
posted for industry comment and ballot. A majority of the edits would simply remove
deregistered functional entities and their applicable requirements/references. Additionally PRC005 will be updated to replace Distribution Providers (DP) with the more-limited UFLS-only DP to
align with the post-RBR registration impacts.
3. Initiatives that can address RBR updates through the periodic review process. This would include
the INT-004 and NUC-001 standards. In other words, rather than making the revisions
immediately, this information would be provided to the periodic review teams currently reviewing
INT-004 and NUC-001 so that any changes resulting from those periodic reviews, if any, may be
proposed at the same time after completion of each periodic review.

Standards affected:
BAL, CIP, IRO and TOP Family of Standards, MOD-032-1 – Data for Power System Modeling and Analysis,
PRC-005-1.1b – Transmission and Generation Protection System Maintenance and Testing, INT-004-3.1 –
Dynamic Transfers, NUC-001-3 – Nuclear Plant Interface Coordination
On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North American
Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) Initiative in Docket No. RR15-4-000.
FERC approved the removal of two functional categories, Purchasing-Selling Entity (PSE) and Interchange
Authority (IA), from the NERC Compliance Registry due to the commercial nature of these categories
posing little or no risk to the reliability of the bulk power system.
FERC also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently approved on
compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria.
Several projects have addressed standards impacted by the RBR initiative since FERC approval; however,
there remain some Reliability Standards that require minor revisions so that they align with the post-RBR
registration impacts.
The time commitment for this project is expected to be up to two face-to-face meetings per quarter
(on average two full working days each meeting) with conference calls scheduled as needed to meet
the agreed-upon timeline the SAR drafting team sets forth. Team members may also have side
projects, either individually or by subgroup, to present to the larger team for discussion and review.
Lastly, an important component of the SAR drafting team effort is outreach. Members of the team will
be expected to conduct industry outreach during the development process to support a successful
project outcome.

Unofficial Nomination Form
Project 2017-07 Standards Alignment with Registration | August 2017

2

Name:
Organization:
Address:
Telephone:
E-mail:
Please briefly describe your experience and qualifications to serve on the requested Standard
Drafting Team (Bio):

If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
Texas RE
FRCC
MRO

NPCC
RF
SERC

SPP RE
WECC
NA – Not Applicable

Unofficial Nomination Form
Project 2017-07 Standards Alignment with Registration | August 2017

3

Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Select each Function 1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator

1

Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner

These functions are defined in the NERC Functional Model, which is available on the NERC web site.

Unofficial Nomination Form
Project 2017-07 Standards Alignment with Registration | August 2017

4

Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:
Name:

Telephone:

Organization:

E-mail:

Name:

Telephone:

Organization:

E-mail:

Provide the name and contact information of your immediate supervisor or a member of your
management who can confirm your organization’s willingness to support your active participation.
Name:

Telephone:

Title:

Email:

Unofficial Nomination Form
Project 2017-07 Standards Alignment with Registration | August 2017

5

Standards Announcement

Project 2017-07 Standards Alignment with Registration

Nomination Period Open through August 14, 2017
Now Available

Nominations are being sought for Standards Authorization Request drafting team members through
8 p.m. Eastern, Monday, August 14, 2017.
Use the electronic form to submit a nomination. If you experience any difficulties in using the
electronic form, contact Nasheema Santos. An unofficial Word version of the nomination form is
posted on the Drafting Team Vacancies page and the project page.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
The time commitment for this project is expected to be two face-to-face meetings per quarter (on
average two full working days each meeting) with conference calls scheduled as needed to meet the
agreed upon timeline the team sets forth. Team members may also have side projects, either
individually or by sub-group, to present for discussion and review. Lastly, an important component
of the team effort is outreach. Members of the team will be expected to conduct industry outreach
during the development process to support a successful ballot.
Previous team experience is beneficial but not required. See the project page and nomination form
for additional information.
Next Steps

The Standards Committee is expected to appoint members to the team in September 2017.
Nominees will be notified shortly after they have been appointed.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Laura Anderson (via email) or at
(404) 446- 9671.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower

Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Solicitation of Standard Drafting Team Nominations
Project 2017-07 Standards Alignment with Registration | August 2017

2

Standard Authorization Request (SAR) Form
Complete and please email this form, with
attachment(s) to: sarcomm@nerc.com

The North American Electric Reliability
Corporation (NERC) welcomes suggestions to
improve the reliability of the bulk power system
through improved Reliability Standards.

Requested information
MOD-032-1 Entity Change Due to Rules of Procedure Modification
06/15/2017

SAR Title:
Date Submitted:
SAR Requester
Name:
Rich Hydzik on behalf of NERC Essential Reliability Resources Work Group
Organization: NERC ERSWG / Avista
Telephone:
509 495 4005
Email:
rich.hydzik@avistacorp.com
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
Withdraw/retire an Existing Standard
Other (Please specify)
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
This project is intended to facilitate accurate data collection to facilitate modeling of the Distribution
Provider’s (DP) facilities.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
Accurate modeling of distribution facilities is required to ensure that power system models accurately
reflect the bulk power system (BPS) performance. These models are used in system analysis for planning
purposes and construction of a reliable BPS. These models are in used in system analysis for operating
purposes to ensure a reliable BPS in both short term, day-ahead, and real-time operational planning
analyses.
Project Scope (Define the parameters of the proposed project):
This project proposes removing the Load Serving Entity (LSE) from the Applicability Section (4.1.3) and
replacing LSE with Distribution Provider (DP) as the applicable entity for Section 4.1.3. LSE is no longer
considered a reliability entity due to a change in the NERC Rules of Procedure. The DP is defined as
“provides and operates the ‘wires’ between the transmission system and the end use customer.” The
DP is the applicable entity to provide data for power system modeling and analysis for distribution
systems. Attachment 1 should be modified by replacing the applicable entity LSE with DP.

1

Requested information
Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification 1which includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g. research paper) to guide development of the Standard or definition):
This project proposes removing the Load Serving Entity (LSE) from the Applicability Section (4.1.3) and
replacing LSE with Distribution Provider (DP) as the applicable entity for Section 4.1.3. LSE is no longer
considered a reliability entity due to a change in the NERC Rules of Procedure. The DP is defined as
“provides and operates the ‘wires’ between the transmission system and the end use customer.” The
DP is the applicable entity to provide data for power system modeling and analysis for distribution
systems.
Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
Cost impacts should be minimal. Planning Coordinator and Transmission Planners are required to collect
modeling data under MOD-032-1. In the past, Planning Coordinator and Transmission Planners collected
from LSE’s. This entity would be the DP under the proposed change.
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g. Dispersed Generation Resources):
None
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
Planning Coordinator
Transmission Planner
Transmission Operator
Distribution Provider
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
No
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so which standard(s) or project number(s)?
No
Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
None identified
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please
attach pertinent information to this form before submittal to NERC.
2 Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted
to obtain industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.
1

2

2.
3.
4.
5.
6.
7.
8.

Reliability Principles
The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
Bulk power systems shall be protected from malicious physical or cyber attacks.

Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Enter
(yes/no)
yes
yes
yes
yes

Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
e.g. NPCC

3

For Use by NERC Only
SAR Status Tracking (Check off as appropriate)
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC

Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document

Version History
Version

Date

Owner

Change Tracking

1

June 3, 2013

Revised

1

August 29, 2014

Standards Information Staff

Updated template

2

January X, 2017

Standards Information Staff

Revised

4

Unofficial Comment Form

Project 2017-07 Standards Alignment with Registration
MOD-032-1 Standards Authorization Request
Do not use this form for submitting comments. Use the electronic form to submit comments on Project
2017-07 Standards Alignment with Registration. The electronic form must be submitted by 8 p.m.
Eastern, Wednesday, August 30, 2017.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the Project 2017-07 Standards Alignment with Registration page. If
you have questions, contact Standards Developer, Laura Anderson (via email), or at 404-446-9671.
Background Information

On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North American
Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) Initiative in Docket No. RR15-4-000.
FERC approved the removal of two functional categories, Purchasing-Selling Entity (PSE) and Interchange
Authority (IA), from the NERC Compliance Registry due to the commercial nature of these categories
posing little or no risk to the reliability of the bulk power system.
FERC also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently approved on
compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria.
Several projects have addressed standards impacted by the RBR initiative since FERC approval; however,
there remain some Reliability Standards that require minor revisions so that they align with the post-RBR
registration impacts.
Project 2017-07 Standards Alignment with Registration is focused on making the tailored Reliability
Standards updates necessary to reflect the retirement of PSEs, IAs, and LSEs (as well as all of their
applicable references). This alignment includes three categories:
1. Modifications to existing standards where the removal of the retired function may need
replacement by another function. Specifically, Reliability Standard MOD-032-1 specifies certain
data from LSEs that may need to be provided by other functional entities going forward.
2. Modifications where the applicable entity and references may be removed. These updates may be
able to follow a similar process to the Paragraph 81 initiatives where standards are redlined and
posted for industry comment and ballot. A majority of the edits would simply remove
deregistered functional entities and their applicable requirements/references. Additionally PRC005 will be updated to replace Distribution Providers (DP) with the more-limited UFLS-only DP to
align with the post-RBR registration impacts.
3. Initiatives that can address RBR updates through the periodic review process. This would include
the INT-004 and NUC-001 standards. In other words, rather than making the revisions
immediately, this information would be provided to the periodic review teams currently reviewing

INT-004 and NUC-001 so that any changes resulting from those periodic reviews, if any, may be
proposed at the same time after completion of each periodic review.

Unofficial Comment Form | MOD-032-1
Project 2017-07 Standards Alignment with Registration | August 2017

2

Questions
1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR for
MOD-032-1? If not, please explain why you do not agree and, if possible, provide specific
language revisions that would make it acceptable to you.
Yes
No
Comments:
2. If you have any other comments on this SAR that you haven’t already mentioned above, please
provide them here:
Comments:

Unofficial Comment Form | MOD-032-1
Project 2017-07 Standards Alignment with Registration | August 2017

3

Standards Announcement

Project 2017-07 Standards Alignment with Registration and
MOD-032-1 Standards Authorization Request
Formal Comment Periods Open through August 30, 2017
Now Available

Simultaneous 30-day formal comment periods on the Standard Authorization Request (SAR) for
Standards Alignment with Registration and the SAR for MOD-032-1 – Data for Power System Modeling
and Analysis are open through 8 p.m. Eastern, Wednesday, August 30, 2017.
Commenting

Use the electronic form to submit comments on the SAR. If you experience any difficulties using the
electronic form, contact Nasheema Santos. The unofficial Word versions of the comment forms are
posted on the project page.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 5 p.m. Eastern).


Passwords expire every 6 months and must be reset.



The SBS is not supported for use on mobile devices.



Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The drafting team will review all responses received during the comment period and determine the next
steps of the project.
For more information on the Standards Development Process, refer to the Standard Processes
Manual.
For more information or assistance, contact Standards Developer, Laura Anderson (via email) or at
(404) 446- 9671.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement
Project 2017-07 Standards Alignment with Registration | August 1, 2017

2

Consideration of Comments
Project Name:

2017-07 Standards Alignment with Registration SAR | MOD-032-1

Comment Period Start Date:

8/1/2017

Comment Period End Date:

8/30/2017

Associated Ballots:

There were 18 sets of responses, including comments from approximately 63 different people from approximately 51 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR for MOD-032-1? If not, please explain
why you do not agree and, if possible, provide specific language revisions that would make it acceptable to you.
2. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

2

Organization
Name

Name

ACES Power Brian Van
Marketing Gheem

Entergy

Northeast
Power

Julie Hall

Segment(s)

6

Region

Group
Member
Name

NA - Not
ACES
Greg
Applicable Standards
Froehling
Collaborators

6

Ruida Shu 1,2,3,4,5,6,7,8,9,10 NPCC

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

Group Name

Group
Member
Segment(s)

Rayburn Country
3
Electric Cooperative,
Inc.

Group
Member
Region
SPP RE

Bob Solomon Hoosier Energy Rural 1
Electric Cooperative,
Inc.

RF

Shari Heino

Brazos Electric
1,5
Power Cooperative,
Inc.

Texas RE

Dave Viar

Southern Maryland 3,4
Electric Cooperative

RF

Amber
Skillern

East Kentucky Power 1,3
Cooperative

SERC

Kevin Lyons

Central Iowa Power 1
Cooperative

MRO

Karl Kohlrus

Prairie Power, Inc.

1,3

SERC

Mark
Ringhausen

Old Dominion
3,4
Electric Cooperative

SERC

Entergy - Entergy
Services, Inc.

1

SERC

Jaclyn Massey Entergy - Entergy
Services, Inc.

5

SERC

Entergy/NERC Oliver Burke
Compliance

RSC

Group Member
Organization

Guy Zito

Northeast Power
NA - Not
Coordinating Council Applicable

NPCC

3

Coordinating
Council

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

Randy
MacDonald

New Brunswick
Power

2

NPCC

Wayne
Sipperly

New York Power
Authority

4

NPCC

Glen Smith

Entergy Services

4

NPCC

Brian
Robinson

Utility Services

5

NPCC

Bruce
Metruck

New York Power
Authority

6

NPCC

Alan Adamson New York State
Reliability Council

7

NPCC

Edward
Bedder

Orange & Rockland
Utilities

1

NPCC

David Burke

Orange & Rockland
Utilities

3

NPCC

Michele
Tondalo

UI

1

NPCC

Laura Mcleod NB Power

1

NPCC

Michael Forte Con Edison

1

NPCC

Kelly Silver

Con Edison

3

NPCC

Peter Yost

Con Edison

4

NPCC

Brian O'Boyle Con Edison

5

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael Jones National Grid

3

NPCC

4

Southwest Shannon
Power Pool, Mickens
Inc. (RTO)

2

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

SPP RE

SPP
Standards
Review
Group

David
Ramkalawan

Ontario Power
Generation Inc.

5

NPCC

Quintin Lee

Eversource Energy

1

NPCC

Kathleen
Goodman

ISO-NE

2

NPCC

Greg Campoli NYISO

2

NPCC

Silvia Mitchell NextEra Energy Florida Power and
Light Co.

6

NPCC

Sean Bodkin

Dominion Dominion
Resources, Inc.

6

NPCC

Paul
Malozewski

Hydro One
Networks, Inc.

3

NPCC

Sylvain
Clermont

Hydro Quebec

1

NPCC

Helen Lainis

IESO

2

NPCC

Chantal
Mazza

Hydro Quebec

2

NPCC

Shannon
Mickens

Southwest Power
Pool Inc.

2

SPP RE

Deborah
McEndaffer

Midwest Energy, Inc NA - Not
Applicable

SPP RE

Mike Kidwell

Empire District
Electric Company

1,3,5

SPP RE

Robert
Hirchak

Cleco Corporation

6

SPP RE

5

Kevin Giles

PPL Louisville
Gas and
Electric Co.

Shelby
Wade

3,5,6

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

RF,SERC

Louisville Gas
and Electric
Company and
Kentucky
Utilities
Company

Westar Energy

1

SPP RE

Tara Lightner Sunflower Electric
Power Corporation

1

SPP RE

Charles
Freibert

PPL - Louisville Gas
and Electric Co.

3

SERC

Dan Wilson

PPL - Louisville Gas
and Electric Co.

5

SERC

Linn Oelker

PPL - Louisville Gas
and Electric Co.

6

SERC

6

1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR for MOD-032-1? If not, please explain
why you do not agree and, if possible, provide specific language revisions that would make it acceptable to you.
Thomas Foltz - AEP - 3,5
Answer

No

Document Name
Comment
While AEP supports the proposed direction and scope of the drafting team as expressed in the two SARs, AEP seeks clarity as to why more
than one SAR is being proposed for a single project. While a project’s SAR may certainly be revised over time as needed, we see no allowance
within Appendix 3A (Standards Process Manual) for multiple, concurrent SARs to govern a single project.
Likes

0

Dislikes

0

Response
Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

No

Document Name
Comment
The project scope proposes to remove Load Serving Entity (LSE) from Attachment 1 and the Applicability Section (4.1.3) of MOD-032-1 and
replace with Distribution Provider (DP) as the applicable entity. The inclusion of the LSE in MOD-032-1 was to allow Planning Coordinators
(PC) and Transmission Planners (TP) to request Demand data from the LSE (see Attachment 1 to MOD-032-1). To replace the LSE with DP is
not effective because Demand data is information that a DP does not have. If the LSE is replaced with the DP in MOD-032-1, in order to
comply, a DP would need to request the LSE data (i.e., Demand) from the Transmission Owner (TO) who would obtain the LSE data through
Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

7

their OATT processes. This process is unnecessarily cumbersome. Since Planning Coordinators and Transmission Planners can request LSE
data from Transmission Owners our suggestion is to simply remove LSE from the Applicability Section (4.1.3), requirements R2 and R3, and
Attachment 1 of MOD-032-1 (but replace LSE with the TO where Demand data is listed in Attachment 1).
Additionally, we believe there is value in finalizing needed updates to the NERC Functional Model and the Functional Model Technical
Document as posted to and commented upon by the industry in September 2016 prior to approving this SAR. Those documents are a useful
guide in understanding the proper scope of the functional roles and how the elimination of certain functional categories can be addressed in
the relevant reliability standards.
Likes

0

Dislikes

0

Response
Stephanie Burns - International Transmission Company Holdings Corporation - 1 - MRO,SPP RE,RF
Answer

No

Document Name
Comment
MOD-032 requires data be provided by applicable entity functions that have been retired. For this standard, this data is critical and the
industry cannot rely on getting data from a functional entity that has no compliance obligation to provide it.
Likes

0

Dislikes

0

Response
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer

No

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

8

Document Name
Comment
We believe references to the reassignment of Load-Serving Entity (LSE) requirements should be broader, as several previous standard
development projects identified other alternative functions (e.g. Resource Planner) instead of one single function (i.e. Distribution
Provider). Moreover, the objective should allow this Standard Drafting Team to revise the requirement to align with those functions’
capabilities. We caution the use of references to model distribution facilities, as these are outside the scope of the BES definition and
Risk-based Registration. Furthermore, many registered entities may operate with smaller non-registered entities and end-user
customers that are not obligated to provide such information to their utilities (e.g. rooftop solar PV resources). We propose limiting
the language of the scope and objectives to only focus on the reassignment of LSE requirements with applicable functions and
revising such requirements to align with those functions’ capabilities.
2. An objective should be included to assess other requirements that could be deemed administrative or align with other Paragraph 81
criteria. Over the past two years, industry and the ERO Enterprise have identified these requirements through a standards grading
evaluation conducted by Regional Entity and NERC Technical Committee representatives.
1.

Likes

0

Dislikes

0

Response
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
We agree with the need to review the alignment issue, but reserve judgment on the proposed changes to the affected standards.
Likes

0

Dislikes

0

Response
Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

9

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
SRP supports the objectives of Project 2017-07 as described in the SAR.
Likes

0

Dislikes

0

Response
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

10

Document Name
Comment
Likes

0

Dislikes

0

Response
Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

11

Response
Daniel Grinkevich - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

Yes

Document Name
Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

12

Comment
Likes

0

Dislikes

0

Response
David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

13

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Michelle Amarantos - APS - Arizona Public Service Co. - 1,3,5,6
Answer

Yes

Document Name
Comment
Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

14

Likes

0

Dislikes

0

Response

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

15

2. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer
Document Name
Comment
We thank you for this opportunity to provide these comments.
Likes

0

Dislikes

0

Response
Stephanie Burns - International Transmission Company Holdings Corporation - 1 - MRO,SPP RE,RF
Answer
Document Name
Comment
The SPP Standards Review Group recommends that the Standards Authorization Request (SAR) author capitalizes the term ‘ bulk power
system’ which is mentioned in the Purpose or Goal Section of the document (page 1). From our perspective, the term is defined in the NERC
Glossary of Terms and not capitalizing it may create confusion on the terms purpose and intent.
Additionally, we recommend that the drafting team review the definition of the term ‘Distribution Provider’ in the NERC Glossary of Terms,
RoP (Appendix 2) and the Functional Model. Through our observation, the definition properly aligns with only two of the three documents
(The NERC Glossary of Terms and RoP) which can be reviewed in the definitions shown below.

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

16

DP (Glossary of Terms and RoP) - Provides and operates the “wires” between the transmission system and the end-use customer. For those
end-use customers who are served at transmission voltages, the Transmission Owner also serves as the Distribution Provider. Thus, the
Distribution Provider is not defined by a specific voltage, but rather as performing the distribution function at any voltage.
DP (Functional Model) - The functional entity that provides facilities that interconnect an End-use Customer load and the electric system for
the transfer of electrical energy to the End-use Customer.
From our perspective, this doesn’t promote consistency in the NERC Documents. We recommend the drafting team develops a SAR to help
initiate the proper alignment of the Functional Model with the other two NERC Documents since it’s referenced in the current SAR. However,
if the drafting team feels that there is no need to align the Functional Model, we would recommend removing the use of the Functional
Model from all NERC Documentation. At its current state, the document has the potential to cause confusion with the interpretation of other
defined term or terms referenced in the two NERC Documents (Glossary of Terms and RoP).
The SPP Standards Review Group has concerns in reference to the DP replacing the LSE in MOD-032.
Currently there is not a DP contact to obtain modeling data, so the data might not be submitted to SPP in a timely manner or at all. SPP
would need time to establish the DP contacts.
Also, we feel that there may be jurisdictional issues pertaining to an entity sharing modeling data if they aren’t registered with NERC as a DP.
Finally, there is a concern in reference to the DP not providing the modeling data on the behalf of the LSE due to the perception they aren’t
responsible to provide the LSE Modeling data.
The SPP Standards Review Group would ask that the drafting team takes into consideration the addition of the Underfrequency Load
Shedding (UFLS) - only DPs to MOD-32-1 Standard Applicability Section. We feel that this entity may have an impact on the role and
responsibilities of providing data to help create productive models.
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

17

Answer
Document Name
Comment
Functional category removal has the potential to impact the newly designated applicable entity for the standard. If applicable, how will the
impact be mitigated? Should this be taken into account as part of a revised implementation plan?
Likes

0

Dislikes

0

Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
The SPP Standards Review Group recommends that the Standards Authorization Request (SAR) author capitalizes the term ‘ bulk power
system’ which is mentioned in the Purpose or Goal Section of the document (page 1). From our perspective, the term is defined in the NERC
Glossary of Terms and not capitalizing it may create confusion on the terms purpose and intent.
Additionally, we recommend that the drafting team review the definition of the term ‘Distribution Provider’ in the NERC Glossary of Terms,
RoP (Appendix 2) and the Functional Model. Through our observation, the definition properly aligns with only two of the three documents
(The NERC Glossary of Terms and RoP) which can be reviewed in the definitions shown below.
DP (Glossary of Terms and RoP) - Provides and operates the “wires” between the transmission system and the end-use customer. For those
end-use customers who are served at transmission voltages, the Transmission Owner also serves as the Distribution Provider. Thus, the
Distribution Provider is not defined by a specific voltage, but rather as performing the distribution function at any voltage.

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

18

DP (Functional Model) - The functional entity that provides facilities that interconnect an End-use Customer load and the electric system for
the transfer of electrical energy to the End-use Customer.
From our perspective, this doesn’t promote consistency in the NERC Documents. We recommend the drafting team develops a SAR to help
initiate the proper alignment of the Functional Model with the other two NERC Documents since it’s referenced in the current SAR. However,
if the drafting team feels that there is no need to align the Functional Model, we would recommend removing the use of the Functional
Model from all NERC Documentation. At its current state, the document has the potential to cause confusion with the interpretation of other
defined term or terms referenced in the two NERC Documents (Glossary of Terms and RoP).
The SPP Standards Review Group has concerns in reference to the DP replacing the LSE in MOD-032.
Currently there is not a DP contact to obtain modeling data, so the data might not be submitted to SPP in a timely manner or at all. SPP
would need time to establish the DP contacts.
Also, we feel that there may be jurisdictional issues pertaining to an entity sharing modeling data if they aren’t registered with NERC as a DP.
Finally, there is a concern in reference to the DP not providing the modeling data on the behalf of the LSE due to the perception they aren’t
responsible to provide the LSE Modeling data.
The SPP Standards Review Group would ask that the drafting team takes into consideration the addition of the Underfrequency Load
Shedding (UFLS) - only DPs to MOD-32-1 Standard Applicability Section. We feel that this entity may have an impact on the role and
responsibilities of providing data to help create productive models.
Likes

0

Dislikes

0

Response
David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name
Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

19

Comment
Functional category removal has the potential to impact the newly designated applicable entity for the standard. If applicable, how will the
impact be mitigated? Should this be taken into account as part of a revised implementation plan?
Likes

0

Dislikes

0

Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
None
Likes

0

Dislikes

0

Response

Consideration of Comments | MOD-032-1 SAR
Project 2017-07 Alignment with Registration | [Month] Year

20

Standard Authorization Request (SAR) Form
Complete and please email this form, with
attachment(s) to: sarcomm@nerc.net

The North American Electric Reliability
Corporation (NERC) welcomes suggestions to
improve the reliability of the bulk power system
through improved Reliability Standards.

Requested information
SAR Title:
Standards Alignment with Registration
Date Submitted:
SAR Requester
Name:
NERC Standards Staff
Organization: NERC
Telephone:
Email:
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
Withdraw/retire an Existing Standard
Other (Please specify)
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
This project will align the standards that are impacted by the Risk-Based Registration (RBR) initiative.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
This project aligns Standards with the FERC-approved RBR initiative.
Project Scope (Define the parameters of the proposed project):
This project will review and align standards impacted by the RBR initiative.
Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification 1which includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g. research paper) to guide development of the Standard or definition):
This project will formally address any remaining edits to the standards that are needed to align the
existing standards with the RBR initiatives. The edits include updates to the BAL, CIP, FAC, INT, IRO,
MOD, NUC, and TOP family of standards to remove the references to Purchasing-Selling Entities (PSEs)
and Interchange Authorities (IAs); references to the Load-Serving Entity (LSEs) will be replaced by either
the Distribution Provider (DP) or the Balancing Authority (BA). Additionally, PRC-005 will replace the
distribution provider with the Underfrequency Load Shedding (UFLS)-only DPs.
The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please
attach pertinent information to this form before submittal to NERC.

1

1

Requested information
The clean-up effort of the standards can be categorized into the following:
1. Modifications to existing standards where the removal of the retired function may need replacement by
another function. Specifically, Reliability Standard MOD-032-1 specifies certain data from LSEs that may
need to be provided by other functional entities going forward. A SAR has been submitted to modify the
MOD standards, and it would be posted with the Alignment with Registration SAR.
2. Modifications where the applicable entity and references may be removed. These updates may be able
to follow a similar process to the Paragraph 81 initiatives where standards are redlined and posted for
industry comment and ballot. A majority of the edits would simply remove deregistered functional
entities and their applicable requirements/references. The impacted standards include the BAL, CIP, IRO,
and TOP family of standards. Additionally PRC-005 will be updated to replace distribution providers with
the more-limited UFLS-only DP to align with the post-RBR registration impacts.
3. Initiatives that can address RBR updates through the periodic review process. This would include the INT004 and NUC-001 standards. In other words, rather than making the revisions immediately, this
information would be provided to the periodic review teams currently reviewing INT-004 and NUC-001 so
that any changes resulting from those periodic reviews, if any, may be proposed at the same time after
completion of each periodic review.

Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
No additional costs outside of the time and resources needed to serve on the SAR and SC team.
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g. Dispersed Generation Resources):
NA
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
Since LSE is being replaced by either a Distribution Provider or Balancing Authority for the standards
that need to be updated, those entities will like be best suited for the MOD and PRC updates.
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
NA
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so which standard(s) or project number(s)?
A separate SAR on the MOD standards was recently received that would be addressed by this project.
Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.

Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted
to obtain industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.

2

2

Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Enter
(yes/no)
Yes
Yes
Yes
Yes

Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
e.g. NPCC

3

For Use by NERC Only
SAR Status Tracking (Check off as appropriate)
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC

Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document

Version History
Version

Date

Owner

Change Tracking

1

June 3, 2013

Revised

1

August 29, 2014

Standards Information Staff

Updated template

2

January X, 2017

Standards Information Staff

Revised

4

Unofficial Comment Form

Project 2017-07 Standards Alignment with Registration
MOD-032-1 Standards Authorization Request
Do not use this form for submitting comments. Use the electronic form to submit comments on Project
2017-07 Standards Alignment with Registration. The electronic form must be submitted by 8 p.m.
Eastern, Wednesday, August 30, 2017.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the Project 2017-07 Standards Alignment with Registration page. If
you have questions, contact Standards Developer, Laura Anderson (via email), or at 404-446-9671.
Background Information

On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North American
Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) Initiative in Docket No. RR15-4-000.
FERC approved the removal of two functional categories, Purchasing-Selling Entity (PSE) and Interchange
Authority (IA), from the NERC Compliance Registry due to the commercial nature of these categories
posing little or no risk to the reliability of the bulk power system.
FERC also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently approved on
compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria.
Several projects have addressed standards impacted by the RBR initiative since FERC approval; however,
there remain some Reliability Standards that require minor revisions so that they align with the post-RBR
registration impacts.
Project 2017-07 Standards Alignment with Registration is focused on making the tailored Reliability
Standards updates necessary to reflect the retirement of PSEs, IAs, and LSEs (as well as all of their
applicable references). This alignment includes three categories:
1. Modifications to existing standards where the removal of the retired function may need
replacement by another function. Specifically, Reliability Standard MOD-032-1 specifies certain
data from LSEs that may need to be provided by other functional entities going forward.
2. Modifications where the applicable entity and references may be removed. These updates may be
able to follow a similar process to the Paragraph 81 initiatives where standards are redlined and
posted for industry comment and ballot. A majority of the edits would simply remove
deregistered functional entities and their applicable requirements/references. Additionally PRC005 will be updated to replace Distribution Providers (DP) with the more-limited UFLS-only DP to
align with the post-RBR registration impacts.
3. Initiatives that can address RBR updates through the periodic review process. This would include
the INT-004 and NUC-001 standards. In other words, rather than making the revisions
immediately, this information would be provided to the periodic review teams currently reviewing

INT-004 and NUC-001 so that any changes resulting from those periodic reviews, if any, may be
proposed at the same time after completion of each periodic review.

Unofficial Comment Form | MOD-032-1
Project 2017-07 Standards Alignment with Registration | August 2017

2

Questions
1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR for
MOD-032-1? If not, please explain why you do not agree and, if possible, provide specific
language revisions that would make it acceptable to you.
Yes
No
Comments:
2. If you have any other comments on this SAR that you haven’t already mentioned above, please
provide them here:
Comments:

Unofficial Comment Form | MOD-032-1
Project 2017-07 Standards Alignment with Registration | August 2017

3

Standards Announcement

Project 2017-07 Standards Alignment with Registration and
MOD-032-1 Standards Authorization Request
Formal Comment Periods Open through August 30, 2017
Now Available

Simultaneous 30-day formal comment periods on the Standard Authorization Request (SAR) for
Standards Alignment with Registration and the SAR for MOD-032-1 – Data for Power System Modeling
and Analysis are open through 8 p.m. Eastern, Wednesday, August 30, 2017.
Commenting

Use the electronic form to submit comments on the SAR. If you experience any difficulties using the
electronic form, contact Nasheema Santos. The unofficial Word versions of the comment forms are
posted on the project page.
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential error
messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/ (Monday –
Friday, 8 a.m. - 5 p.m. Eastern).


Passwords expire every 6 months and must be reset.



The SBS is not supported for use on mobile devices.



Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The drafting team will review all responses received during the comment period and determine the next
steps of the project.
For more information on the Standards Development Process, refer to the Standard Processes
Manual.
For more information or assistance, contact Standards Developer, Laura Anderson (via email) or at
(404) 446- 9671.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement
Project 2017-07 Standards Alignment with Registration | August 1, 2017

2

Comment Report
Project Name:

2017-07 Standards Alignment with Registration SAR

Comment Period Start Date:

8/1/2017

Comment Period End Date:

8/30/2017

Associated Ballots:

There were 19 sets of responses, including comments from approximately 64 different people from approximately 52 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR? If not, please explain why you do not
agree and, if possible, provide specific language revisions that would make it acceptable to you.

2. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:

Organization
Name
ACES Power
Marketing

Entergy

Northeast
Power
Coordinating
Council

Name

Brian Van
Gheem

Julie Hall

Ruida Shu

Segment(s)

6

Region

NA - Not
Applicable

6

1,2,3,4,5,6,7,8,9,10 NPCC

Group Name

ACES
Standards
Collaborators

Group Member
Name

Group
Member
Segment(s)

Group Member
Region

Greg Froehling

Rayburn
Country
Electric
Cooperative,
Inc.

3

SPP RE

Bob Solomon

Hoosier
Energy Rural
Electric
Cooperative,
Inc.

1

RF

Shari Heino

Brazos
1,5
Electric Power
Cooperative,
Inc.

Texas RE

Dave Viar

Southern
Maryland
Electric
Cooperative

RF

Amber Skillern

East Kentucky 1,3
Power
Cooperative

SERC

Kevin Lyons

Central Iowa
Power
Cooperative

MRO

Karl Kohlrus

Prairie Power, 1,3
Inc.

SERC

Mark Ringhausen Old Dominion 3,4
Electric
Cooperative

SERC

Entergy/NERC Oliver Burke
Compliance

RSC

Group
Member
Organization

3,4

1

Entergy 1
Entergy
Services, Inc.

SERC

Jaclyn Massey

Entergy 5
Entergy
Services, Inc.

SERC

Guy Zito

Northeast
Power
Coordinating
Council

NA - Not
Applicable

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Wayne Sipperly

New York
Power
Authority

4

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian Robinson

Utility Services 5

NPCC

Bruce Metruck

New York
Power
Authority

6

NPCC

Alan Adamson

New York
State
Reliability
Council

7

NPCC

Edward Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele Tondalo

UI

1

NPCC

Laura Mcleod

NB Power

1

NPCC

Michael Forte

Con Edison

1

NPCC

Kelly Silver

Con Edison

3

NPCC

Peter Yost

Con Edison

4

NPCC

Brian O'Boyle

Con Edison

5

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael Jones

National Grid

3

NPCC

David
Ramkalawan

Ontario Power 5
Generation
Inc.

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

Kathleen
Goodman

ISO-NE

2

NPCC

Greg Campoli

NYISO

2

NPCC

Silvia Mitchell

NextEra
6
Energy Florida Power
and Light Co.

NPCC

Sean Bodkin

Dominion Dominion

NPCC

6

Resources,
Inc.
Paul Malozewski

Southwest
Power Pool,
Inc. (RTO)

Shannon
Mickens

PPL Shelby Wade
Louisville Gas
and Electric
Co.

2

3,5,6

SPP RE

RF,SERC

Hydro One
3
Networks, Inc.

NPCC

Sylvain Clermont Hydro Quebec 1

NPCC

Helen Lainis

IESO

2

NPCC

Chantal Mazza

Hydro Quebec 2

NPCC

SPP
Shannon Mickens Southwest
Standards
Power Pool
Inc.
Review Group

2

SPP RE

NA - Not
Applicable

SPP RE

Deborah
McEndaffer

Midwest
Energy, Inc

Mike Kidwell

Empire District 1,3,5
Electric
Company

SPP RE

Robert Hirchak

Cleco
Corporation

6

SPP RE

Kevin Giles

Westar
Energy

1

SPP RE

Tara Lightner

Sunflower
1
Electric Power
Corporation

SPP RE

PPL 3
Louisville Gas
and Electric
Co.

SERC

PPL 5
Louisville Gas
and Electric
Co.

SERC

PPL 6
Louisville Gas
and Electric
Co.

SERC

Louisville Gas Charles Freibert
and Electric
Company and
Kentucky
Utilities
Dan Wilson
Company

Linn Oelker

1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR? If not, please explain why you do not
agree and, if possible, provide specific language revisions that would make it acceptable to you.
Thomas Foltz - AEP - 3,5
Answer

No

Document Name
Comment

While AEP supports the proposed direction and scope of the drafting team as expressed in the two SARs, AEP seeks clarity as to why more than one
SAR is being proposed for a single project. While a project’s SAR may certainly be revised over time as needed, we see no allowance within Appendix
3A (Standards Process Manual) for multiple, concurrent SARs to govern a single project.

Likes

0

Dislikes

0

Response

Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

No

Document Name
Comment
We agree with the proposed objectives of the SAR but believe the scope should be expanded to include a review of he Glossary. (The SAR form needs
an additional box check in the “SAR Type” i.e. “Add, Modify or Retire a Glossary Term”. )
The terms Interchange Authority (IA), Load-Serving Entity (LSE) and Purchasing-Selling Entities (PSE) are used in NERC Glossary definitions
and NERC should make sure that these definitions are still valid and aligned with the standards in which they are used.
For example, the NERC Glossary uses “Interchange Authority” in the definitions of Arranged Interchange, Confirmed Interchange, and Request for
Interchange and these terms as well as the definition of “Interchange Authority” itself do not necessarily align with the project on the INT standards
where the BA took on the IA’s reliability tasks.
Also LSE is used in the definitions of Energy Emergency, Interruptible Load, DSM, etc
Likes

0

Dislikes
Response

0

Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
1. We believe references to the reassignment of Load-Serving Entity (LSE) requirements should be broader instead of limiting the selection to
either the Distribution Provider (DP) or the Balancing Authority (BA). During previous standard development projects, other functions (e.g.
Resource Planner) were identified as applicable instead of DPs and BAs. Moreover, the objective should allow this Standard Drafting Team to
revise the requirement to align with those functions’ capabilities. Many registered entities may operate with smaller non-registered entities and
end-user customers that are not obligated to provide such information to their utilities (e.g. rooftop solar PV resources). We propose revising
the objective to read “references to LSE requirements will be reassigned to applicable functions and revised to align with those functions’
capabilities.”
2. An objective should be included to assess other requirements that could be deemed administrative or align with other Paragraph 81 criteria.
Over the past two years, industry and the ERO Enterprise have identified these requirements through a standards grading evaluation conducted
by Regional Entity and NERC Technical Committee representatives.
Likes

0

Dislikes

0

Response

Michelle Amarantos - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment
AZPS requests clarification to ensure that the directives to the SDT are clear and definitive. To eliminate ambiguity, AZPS recommends that the
following sentence be revised as indicated below.
“The edits include updates to the BAL, CIP, FAC, INT, IRO, MOD, NUC, and TOP family of standards to:
•
•

Delete remove the references to Purchasing-Selling Entities (PSEs) and Interchange Authorities (IAs);
Revise references to the Load-Serving Entity (LSEs) by replacing these references with:
o either the Distribution Provider (DP) or the Balancing Authority (BA);
o Distribution Provider; or
o Balancing Authority.”

In addition, AZPS requests clarification regarding how the determination will be made to replace LSEs with either DP or BA, DP, or BA. For example,
will the SDT be required to establish criteria to determine if LSE is replaced with a DP, BA, Option for Either or None (removal)?
Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2

Answer

Yes

Document Name
Comment
We agree with the need to review the alignment issue, but reserve judgment on the proposed changes to the affected standards.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
SRP supports the objectives of Project 2017-07 as described in the SAR.
Likes

0

Dislikes

0

Response

Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Daniel Grinkevich - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

2. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:
Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer
Document Name
Comment
1. The SAR type should include the retirement of a standard, as there is a possibility that all requirements of a standard could be retired as part of
this project.
2. The unique characteristics of the BES facilities that may be impacted by this proposed standard development project should be identified as
“None” instead of not applicable.
3. We believe two Reliability Principles are applicable to this standard development project. This project will revise requirements for applicable
entities that plan and operate interconnected bulk power systems in a coordinated manner. Moreover, the project will revise requirements
applicable to identifying information that is necessary for the planning and operation of interconnected bulk power systems and its availability for
responsible entities.
4. We thank you for this opportunity to provide these comments.
Likes

0

Dislikes

0

Response

Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer
Document Name
Comment
Based on the proposed changes to the Applicability Section of PRC-005, Tri-State believes PRC-004 applicability should also be updated to replace
Distribution Provider with UFLS-only DP. As currently written in the SAR, we believe the PRC-005 applicability would become inconsistent with the
current version of PRC-004.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE is concerned with the proposed change to the Applicability section in Reliability Standard PRC-005-6. The SAR proposes to replace

Distribution Provider (DP) with Underfrequency Load Shedding (UFLS)-only DPs. This could result in section 4.1 conflicting with section 4.2.1, which
includes Protection Systems and Sudden Pressure Relaying that are installed for the purpose of detecting Faults on BES elements. This could include
DPs that do not have UFLS.
Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer
Document Name
Comment
a)
Functional category removal has the potential to impact the newly designated applicable entity for the standard. If applicable how will the impact
be mitigated? Should this be taken into account as part of a revised implementation plan?
b)
Alignment category number 2 should include the currently existing, in progress, standards revision as part of the regional reliability standards
revision driven by NPCC. Specifically NERC should coordinate with NPCC the revision of the standard PRC-006-NPCC-2 Automatic Underfrequency
Load Shedding. For example Requirement Part 16.3 “Have compensatory load shedding, as provided by a Distribution Provider or Transmission Owner
that is adequate to compensate for the loss of their generator due to early tripping.” should now be transferred to Underfrequency Load Shedding
(UFLS)-only Distribution Provider (DP). In other words the NERC revision of standards should be coordinated with the regional entities to avoid having
conflicting regulatory requirements in effect at the same time (i.e. different owners for the same regulatory requirement)
c)

There is a potential risk for conflicting regulatory requirements due to different timelines for the Periodic Review of various standards.

The SAR form should check an additional box in the “SAR Type” i.e. “Add, Modify or Retire a Glossary Term”. The terms Interchange Authority (IA),
Load-Serving Entity (LSE) and Purchasing-Selling Entities are used in NERC Glossary definitions and the SAR or Standard drafting team should make
sure that these definitions are still valid. For example, the NERC Glossary uses “Interchange Authority” in the definitions of Arranged Interchange,
Confirmed Interchange, and Request for Interchange and these terms as well as the definition of “Interchange Authority” itself do not necessarily align
with the project on the INT standards where the BA took on the IA’s reliability tasks. Also LSE is used in the definitions of Energy Emergency,
Interruptible Load, DSM, etc.
Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name

Comment
OPG is of the opinion that:
1. Functional category removal has the potential to impact the newly designated applicable entity for the standard. If applicable how will the
impact be mitigated? Should this be taken into account as part of a revised implementation plan?
2. Alignment category number 2 should include the currently existing, in progress, standards revision as part of the regional reliability standards
revision driven by NPCC. Specifically NERC should coordinate with NPCC the revision of the standard PRC-006-NPCC-2 Automatic
Underfrequency Load Shedding. For example Requirement Part 16.3 “Have compensatory load shedding, as provided by a Distribution
Provider or Transmission Owner that is adequate to compensate for the loss of their generator due to early tripping.” should now be transferred
to Underfrequency Load Shedding (UFLS)-only Distribution Provider (DP). In other words the NERC revision of standards should be
coordinated with the regional entities to avoid having conflicting regulatory requirements in effect at the same time (i.e. different owners for the
same regulatory requirement)
3. There is a potential risk for conflicting regulatory requirements due to different timelines for the Periodic Review of various standards.
Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
The SPP Standards Review Group recommends that the drafting team review the definitions of the terms ‘Distribution Provider’ and ‘Balancing
Authority’ in the NERC Glossary of Terms, RoP (Appendix 2) and the Functional Model. Through our observation, the definitions are properly aligned
with only two of the three documents (The NERC Glossary of Terms and RoP) which can be reviewed in the definitions shown below.
DP (Glossary of Terms and RoP) - Provides and operates the “wires” between the transmission system and the end-use customer. For those end-use
customers who are served at transmission voltages, the Transmission Owner also serves as the Distribution Provider. Thus, the Distribution Provider is
not defined by a specific voltage, but rather as performing the distribution function at any voltage.
DP (Functional Model) - The functional entity that provides facilities that interconnect an End-use Customer load and the electric system for the transfer
of electrical energy to the End-use Customer.
BA (Glossary of Terms and RoP) - The responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance
within a Balancing Authority Area, and supports Interconnection frequency in real time.
BA (Functional Model) - The functional entity that integrates resource plans ahead of time, maintains generation-load-interchange-balance within a
Balancing Authority Area, and contributes to Interconnection frequency in real time.
From our perspective, this doesn’t promote consistency in the NERC Documents. We recommend the drafting team develops a SAR to help initiate the
proper alignment of the Functional Model with the other two NERC Documents since it’s referenced in the current SAR. However, if the drafting team
feels that there is no need to align the Functional Model, we would recommend removing the use of the Functional Model from all NERC
Documentation. At its current state, the document has the potential to cause confusion with the interpretation of other defined terms referenced in the

two NERC Documents (Glossary of Terms and RoP).
Likes

0

Dislikes

0

Response

Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer
Document Name
Comment
Within the Detailed Description section of the SAR, the clean-up effort of the standards are divided into three categories: (1) removal of the retired
function and replacement by another function, (2) removal of the deregistered functional entities and their applicable requirements/references, and (3)
initiatives that can address RBR updates through the periodic review process.
The second sentence of the Detailed Description states “The edits include updates to the BAL, CIP, FAC, INT, IRO, MOD, NUC, and TOP family of
standards to remove the references to Purchasing-Selling Entities (PSEs) and Interchange Authorities (IAs); references to the Load-Serving Entity
(LSEs) will be replaced by either the Distribution Provider (DP) or the Balancing Authority (BA).”
As currently written, the second sentence of the Detailed Description indicates removing and replacing references to the LSE with the DP as the only
change that will be given consideration with respect to the LSE-related changes (Category 1 of the clean-up effort). It does not contemplate
consideration of simply removing the applicable requirements with respect to and references to the LSE within relevant standards (Category 2 of the
clean-up effort). To correct this misalignment or potential conflict within the Detailed Description, we recommend that the second sentence of the
Detailed Description be revised to state:
“The edits include updates to the BAL, CIP, FAC, INT, IRO, MOD, NUC, and TOP family of standards to remove the applicable requirements with
respect to and references to Purchasing-Selling Entities (PSEs), Interchange Authorities (IAs), and Load Serving Entities (LSEs) and their applicable
requirements/references; or with respect to LSEs, remove the applicable requirements with respect to and replace the references to the LSE with either
the Distribution Provider (DP) or the Balancing Authority (BA) or another functional role if appropriate.”
Additionally, we believe there is value in finalizing needed updates to the NERC Functional Model and the Functional Model Technical Document as
posted to and commented upon by the industry in September 2016 prior to approving this SAR. Those documents are a useful guide in understanding
the proper scope of the functional roles and how the elimination of certain functional categories can be addressed in the relevant reliability standards.
Likes

0

Dislikes

0

Response

Michael Jones - National Grid USA - 1,3,5
Answer
Document Name
Comment

Should PRC-005 be applicable to Distribution Providers and the sub-set UFLS-only DP? For PRC-005, it may not be appropriate to replace Distribution
Providers with the more limiting “UFLS-only DP” applicability.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
None
Likes

0

Dislikes
Response

0

Consideration of Comments
Project Name:

2017-07 Standards Alignment with Registration SAR

Comment Period Start Date:

8/1/2017

Comment Period End Date:

8/30/2017

Associated Ballots:

There were 19 sets of responses, including comments from approximately 64 different people from approximately 52 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR? If not, please explain why you do not
agree and, if possible, provide specific language revisions that would make it acceptable to you.
2. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:

Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

2

Organization
Name

Name

ACES Power Brian Van
Marketing Gheem

Entergy

Julie Hall

Segment(s)

6

Region

Group Name

Group
Member
Name

Group Member
Organization

Group Member
Segment(s)

Group Member
Region

NA - Not ACES
Greg Froehling Rayburn Country
Applicable Standards
Electric
Collaborators
Cooperative, Inc.

3

SPP RE

Bob Solomon Hoosier Energy
Rural Electric
Cooperative, Inc.

1

RF

Shari Heino

Brazos Electric
Power
Cooperative, Inc.

1,5

Texas RE

Dave Viar

Southern
3,4
Maryland Electric
Cooperative

6

Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

RF

Amber Skillern East Kentucky
Power
Cooperative

1,3

SERC

Kevin Lyons

Central Iowa
Power
Cooperative

1

MRO

Karl Kohlrus

Prairie Power, Inc. 1,3

SERC

Mark
Ringhausen

Old Dominion
Electric
Cooperative

SERC

Entergy/NERC Oliver Burke
Compliance

3,4

Entergy - Entergy 1
Services, Inc.

SERC

3

Jaclyn Massey Entergy - Entergy 5
Services, Inc.
Northeast
Ruida Shu 1,2,3,4,5,6,7 NPCC
Power
,8,9,10
Coordinating
Council

RSC

Guy Zito

Northeast Power
Coordinating
Council

NA - Not Applicable NPCC

Randy
MacDonald

New Brunswick
Power

2

NPCC

Wayne
Sipperly

New York Power
Authority

4

NPCC

Glen Smith

Entergy Services

4

NPCC

Brian
Robinson

Utility Services

5

NPCC

6

NPCC

Alan Adamson New York State
7
Reliability Council

NPCC

Edward
Bedder

Orange &
1
Rockland Utilities

NPCC

David Burke

Orange &
3
Rockland Utilities

NPCC

Michele
Tondalo

UI

1

NPCC

Laura Mcleod NB Power

1

NPCC

Michael Forte Con Edison

1

NPCC

Kelly Silver

Con Edison

3

NPCC

Peter Yost

Con Edison

4

NPCC

Bruce Metruck New York Power
Authority

Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

SERC

4

Brian O'Boyle Con Edison

5

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael Jones National Grid

3

NPCC

David
Ramkalawan

Ontario Power
Generation Inc.

5

NPCC

Quintin Lee

Eversource Energy 1

NPCC

Kathleen
Goodman

ISO-NE

2

NPCC

2

NPCC

Silvia Mitchell NextEra Energy - 6
Florida Power and
Light Co.

NPCC

Sean Bodkin

Dominion Dominion
Resources, Inc.

6

NPCC

Paul
Malozewski

Hydro One
Networks, Inc.

3

NPCC

Sylvain
Clermont

Hydro Quebec

1

NPCC

Helen Lainis

IESO

2

NPCC

2

NPCC

Greg Campoli NYISO

Chantal Mazza Hydro Quebec
Southwest Shannon
Power Pool, Mickens
Inc. (RTO)

2

SPP RE

Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

SPP Standards Shannon
Review Group Mickens
Deborah
McEndaffer

Southwest Power 2
Pool Inc.
Midwest Energy,
Inc

SPP RE

NA - Not Applicable SPP RE

5

PPL Louisville
Gas and
Electric Co.

Shelby
Wade

3,5,6

RF,SERC

Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

Mike Kidwell

Empire District
1,3,5
Electric Company

SPP RE

Robert
Hirchak

Cleco Corporation 6

SPP RE

Kevin Giles

Westar Energy

1

SPP RE

Tara Lightner

Sunflower Electric 1
Power
Corporation

SPP RE

Louisville Gas Charles
and Electric
Freibert
Company and
Kentucky
Dan Wilson
Utilities
Company

PPL - Louisville
Gas and Electric
Co.

3

SERC

PPL - Louisville
Gas and Electric
Co.

5

SERC

Linn Oelker

PPL - Louisville
Gas and Electric
Co.

6

SERC

6

1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR? If not, please explain why you do not
agree and, if possible, provide specific language revisions that would make it acceptable to you.
Summary Responses:
The SAR Drafting Team received comments requesting clarity as to why more than one SAR was being proposed for Project 2017-07
Standards Alignment with Registration.
• The SAR Drafting Team has merged the two SARs into a single SAR for Project 2017-07.
Several commenters requested that the SAR Drafting Team expand the scope of the project and include in the SAR a review of the NERC
Glossary of Terms and to validate that the terms Interchange Authority (IA), Load-Serving Entity (LSE), and Purchasing-Selling Entities (PSE) are
appropriate and align with the standards in which they are used. In addition, there were comments related to the definition of
Underfrequency Load Serving (UFLS)-only Distribution Providers (DPs).
•
•

The SAR Drafting Team considered these comments but does not agree with changing the SAR to include a review of the NERC
Glossary of Terms for IA, LSE and PSE. The LSE, IA, and PSE will continue to be referenced in resource documents, etc., as the function
does not go away.
UFLS-only DPs are a limited number of entities who have UFLS obligations, but who otherwise do not meet any of the registration
criteria of a DP. While the term “Distribution Provider” is defined in the NERC Glossary of Terms, there is no reason to define UFLSonly DPs as a unique term, as it is only a subset of the functional registration DP.

To address comments received, the SAR Drafting Team has updated the language of the SAR, which now states, “remove or replace
references to the Load-Serving Entity (LSEs) by either the Distribution Provider (DP), the Balancing Authority (BA), or other appropriate
functional entity.”
Thomas Foltz - AEP - 3,5
Answer

No

Document Name
Comment

Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

7

While AEP supports the proposed direction and scope of the drafting team as expressed in the two SARs, AEP seeks clarity as to why more
than one SAR is being proposed for a single project. While a project’s SAR may certainly be revised over time as needed, we see no allowance
within Appendix 3A (Standards Process Manual) for multiple, concurrent SARs to govern a single project.
Likes

0

Dislikes

0

Response
Nicolas Turcotte - Hydro-Qu?bec TransEnergie - 1
Answer

No

Document Name
Comment
We agree with the proposed objectives of the SAR but believe the scope should be expanded to include a review of he Glossary. (The SAR
form needs an additional box check in the “SAR Type” i.e. “Add, Modify or Retire a Glossary Term”. )
The terms Interchange Authority (IA), Load-Serving Entity (LSE) and Purchasing-Selling Entities (PSE) are used in NERC Glossary definitions
and NERC should make sure that these definitions are still valid and aligned with the standards in which they are used.
For example, the NERC Glossary uses “Interchange Authority” in the definitions of Arranged Interchange, Confirmed Interchange, and
Request for Interchange and these terms as well as the definition of “Interchange Authority” itself do not necessarily align with the project
on the INT standards where the BA took on the IA’s reliability tasks.
Also LSE is used in the definitions of Energy Emergency, Interruptible Load, DSM, etc
Likes

0

Dislikes

0

Response
Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

8

Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer

No

Document Name
Comment
1. We believe references to the reassignment of Load-Serving Entity (LSE) requirements should be broader instead of limiting the
selection to either the Distribution Provider (DP) or the Balancing Authority (BA). During previous standard development projects,
other functions (e.g. Resource Planner) were identified as applicable instead of DPs and BAs. Moreover, the objective should allow
this Standard Drafting Team to revise the requirement to align with those functions’ capabilities. Many registered entities may
operate with smaller non-registered entities and end-user customers that are not obligated to provide such information to their
utilities (e.g. rooftop solar PV resources). We propose revising the objective to read “references to LSE requirements will be
reassigned to applicable functions and revised to align with those functions’ capabilities.”
2. An objective should be included to assess other requirements that could be deemed administrative or align with other Paragraph 81
criteria. Over the past two years, industry and the ERO Enterprise have identified these requirements through a standards grading
evaluation conducted by Regional Entity and NERC Technical Committee representatives.
Likes

0

Dislikes

0

Response
Michelle Amarantos - APS - Arizona Public Service Co. - 1,3,5,6
Answer

No

Document Name
Comment
AZPS requests clarification to ensure that the directives to the SDT are clear and definitive. To eliminate ambiguity, AZPS recommends that
the following sentence be revised as indicated below.
Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

9

“The edits include updates to the BAL, CIP, FAC, INT, IRO, MOD, NUC, and TOP family of standards to:
1.
2.
1.
2.
3.

Delete remove the references to Purchasing-Selling Entities (PSEs) and Interchange Authorities (IAs);
Revise references to the Load-Serving Entity (LSEs) by replacing these references with:
either the Distribution Provider (DP) or the Balancing Authority (BA);
Distribution Provider; or
Balancing Authority.”

In addition, AZPS requests clarification regarding how the determination will be made to replace LSEs with either DP or BA, DP, or BA. For
example, will the SDT be required to establish criteria to determine if LSE is replaced with a DP, BA, Option for Either or None (removal)?
Likes

0

Dislikes

0

Response
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
We agree with the need to review the alignment issue, but reserve judgment on the proposed changes to the affected standards.
Likes

0

Dislikes

0

Response
Thank you for your comment.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

10

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
SRP supports the objectives of Project 2017-07 as described in the SAR.
Likes

0

Dislikes

0

Response
Rick Applegate - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Document Name
Comment

Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

11

Likes

0

Dislikes

0

Response
Julie Hall - Entergy - 6, Group Name Entergy/NERC Compliance
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC,SPP RE
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Daniel Grinkevich - Con Ed - Consolidated Edison Co. of New York - 1,3,5,6
Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

12

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Elizabeth Axson - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer

Yes

Document Name
Comment
Likes

0

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Project 2017-07 Alignment with Registration | December 2017

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Dislikes

0

Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

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Project 2017-07 Alignment with Registration | December 2017

14

Document Name
Comment
Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

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Response

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16

2. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:
Summary Responses:
Based on comments received, the SAR Drafting Team has updated the language of the SAR, which now states, “remove or replace references
to the Load-Serving Entity (LSEs) by either the Distribution Provider (DP), the Balancing Authority (BA), or other appropriate functional entity.”
There were comments received stating concerns with the proposed change to the Applicability Section in PRC-005-6. The Draft 1 SAR
proposed to replace DP with UFLS-only DPs, creating a possible conflict resulting in Section 4.1 with Section 4.2.1.
•

The SAR Drafting Team agreed with the comments received and updated the language in the SAR by deleting “removing UFLS-only DP”
and changing the language to “adding UFLS-only DP.”

Brian Van Gheem - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standards Collaborators
Answer
Document Name
Comment
1. The SAR type should include the retirement of a standard, as there is a possibility that all requirements of a standard could be retired
as part of this project.
2. The unique characteristics of the BES facilities that may be impacted by this proposed standard development project should be
identified as “None” instead of not applicable.
3. We believe two Reliability Principles are applicable to this standard development project. This project will revise requirements for
applicable entities that plan and operate interconnected bulk power systems in a coordinated manner. Moreover, the project will
revise requirements applicable to identifying information that is necessary for the planning and operation of interconnected bulk
power systems and its availability for responsible entities.
4. We thank you for this opportunity to provide these comments.
Likes

0

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0

Response
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17

Thank you for your comments.
1.
All of the proposed standards within the SAR have applicable entities in addition to the PSE, LSE and IA.
2.
Change made
3.
Updated in SAR
Sergio Banuelos - Tri-State G and T Association, Inc. - 1,3,5 - MRO,WECC
Answer
Document Name
Comment
Based on the proposed changes to the Applicability Section of PRC-005, Tri-State believes PRC-004 applicability should also be updated to
replace Distribution Provider with UFLS-only DP. As currently written in the SAR, we believe the PRC-005 applicability would become
inconsistent with the current version of PRC-004.
Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE is concerned with the proposed change to the Applicability section in Reliability Standard PRC-005-6. The SAR proposes to replace
Distribution Provider (DP) with Underfrequency Load Shedding (UFLS)-only DPs. This could result in section 4.1 conflicting with section 4.2.1,
which includes Protection Systems and Sudden Pressure Relaying that are installed for the purpose of detecting Faults on BES elements. This
could include DPs that do not have UFLS.

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Project 2017-07 Alignment with Registration | December 2017

18

Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer
Document Name
Comment
a) Functional category removal has the potential to impact the newly designated applicable entity for the standard. If applicable how will
the impact be mitigated? Should this be taken into account as part of a revised implementation plan?
b) Alignment category number 2 should include the currently existing, in progress, standards revision as part of the regional reliability
standards revision driven by NPCC. Specifically NERC should coordinate with NPCC the revision of the standard PRC-006-NPCC-2 Automatic
Underfrequency Load Shedding. For example Requirement Part 16.3 “Have compensatory load shedding, as provided by a Distribution
Provider or Transmission Owner that is adequate to compensate for the loss of their generator due to early tripping.” should now be
transferred to Underfrequency Load Shedding (UFLS)-only Distribution Provider (DP). In other words the NERC revision of standards should be
coordinated with the regional entities to avoid having conflicting regulatory requirements in effect at the same time (i.e. different owners for
the same regulatory requirement)
c)

There is a potential risk for conflicting regulatory requirements due to different timelines for the Periodic Review of various standards.

The SAR form should check an additional box in the “SAR Type” i.e. “Add, Modify or Retire a Glossary Term”. The terms Interchange Authority
(IA), Load-Serving Entity (LSE) and Purchasing-Selling Entities are used in NERC Glossary definitions and the SAR or Standard drafting team
should make sure that these definitions are still valid. For example, the NERC Glossary uses “Interchange Authority” in the definitions of
Arranged Interchange, Confirmed Interchange, and Request for Interchange and these terms as well as the definition of “Interchange
Authority” itself do not necessarily align with the project on the INT standards where the BA took on the IA’s reliability tasks. Also LSE is used
in the definitions of Energy Emergency, Interruptible Load, DSM, etc.

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Likes

0

Dislikes

0

Response
David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG is of the opinion that:
1. Functional category removal has the potential to impact the newly designated applicable entity for the standard. If applicable how
will the impact be mitigated? Should this be taken into account as part of a revised implementation plan?
2. Alignment category number 2 should include the currently existing, in progress, standards revision as part of the regional reliability
standards revision driven by NPCC. Specifically NERC should coordinate with NPCC the revision of the standard PRC-006-NPCC-2
Automatic Underfrequency Load Shedding. For example Requirement Part 16.3 “Have compensatory load shedding, as provided by a
Distribution Provider or Transmission Owner that is adequate to compensate for the loss of their generator due to early tripping.”
should now be transferred to Underfrequency Load Shedding (UFLS)-only Distribution Provider (DP). In other words the NERC revision
of standards should be coordinated with the regional entities to avoid having conflicting regulatory requirements in effect at the same
time (i.e. different owners for the same regulatory requirement)
3. There is a potential risk for conflicting regulatory requirements due to different timelines for the Periodic Review of various standards.
Likes

0

Dislikes

0

Response

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Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
The SPP Standards Review Group recommends that the drafting team review the definitions of the terms ‘Distribution Provider’ and
‘Balancing Authority’ in the NERC Glossary of Terms, RoP (Appendix 2) and the Functional Model. Through our observation, the definitions are
properly aligned with only two of the three documents (The NERC Glossary of Terms and RoP) which can be reviewed in the definitions shown
below.
DP (Glossary of Terms and RoP) - Provides and operates the “wires” between the transmission system and the end-use customer. For those
end-use customers who are served at transmission voltages, the Transmission Owner also serves as the Distribution Provider. Thus, the
Distribution Provider is not defined by a specific voltage, but rather as performing the distribution function at any voltage.
DP (Functional Model) - The functional entity that provides facilities that interconnect an End-use Customer load and the electric system for
the transfer of electrical energy to the End-use Customer.
BA (Glossary of Terms and RoP) - The responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation
balance within a Balancing Authority Area, and supports Interconnection frequency in real time.
BA (Functional Model) - The functional entity that integrates resource plans ahead of time, maintains generation-load-interchange-balance
within a Balancing Authority Area, and contributes to Interconnection frequency in real time.
From our perspective, this doesn’t promote consistency in the NERC Documents. We recommend the drafting team develops a SAR to help
initiate the proper alignment of the Functional Model with the other two NERC Documents since it’s referenced in the current SAR. However,
if the drafting team feels that there is no need to align the Functional Model, we would recommend removing the use of the Functional
Model from all NERC Documentation. At its current state, the document has the potential to cause confusion with the interpretation of other
defined terms referenced in the two NERC Documents (Glossary of Terms and RoP).
Likes
Dislikes

0
0

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Response
Shelby Wade - PPL - Louisville Gas and Electric Co. - 3,5,6 - SERC, Group Name Louisville Gas and Electric Company and Kentucky Utilities
Company
Answer
Document Name
Comment
Within the Detailed Description section of the SAR, the clean-up effort of the standards are divided into three categories: (1) removal of the
retired function and replacement by another function, (2) removal of the deregistered functional entities and their applicable
requirements/references, and (3) initiatives that can address RBR updates through the periodic review process.
The second sentence of the Detailed Description states “The edits include updates to the BAL, CIP, FAC, INT, IRO, MOD, NUC, and TOP family
of standards to remove the references to Purchasing-Selling Entities (PSEs) and Interchange Authorities (IAs); references to the Load-Serving
Entity (LSEs) will be replaced by either the Distribution Provider (DP) or the Balancing Authority (BA).”
As currently written, the second sentence of the Detailed Description indicates removing and replacing references to the LSE with the DP as
the only change that will be given consideration with respect to the LSE-related changes (Category 1 of the clean-up effort). It does not
contemplate consideration of simply removing the applicable requirements with respect to and references to the LSE within relevant
standards (Category 2 of the clean-up effort). To correct this misalignment or potential conflict within the Detailed Description, we
recommend that the second sentence of the Detailed Description be revised to state:
“The edits include updates to the BAL, CIP, FAC, INT, IRO, MOD, NUC, and TOP family of standards to remove the applicable requirements
with respect to and references to Purchasing-Selling Entities (PSEs), Interchange Authorities (IAs), and Load Serving Entities (LSEs) and their
applicable requirements/references; or with respect to LSEs, remove the applicable requirements with respect to and replace the references
to the LSE with either the Distribution Provider (DP) or the Balancing Authority (BA) or another functional role if appropriate.”
Additionally, we believe there is value in finalizing needed updates to the NERC Functional Model and the Functional Model Technical
Document as posted to and commented upon by the industry in September 2016 prior to approving this SAR. Those documents are a useful

Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

22

guide in understanding the proper scope of the functional roles and how the elimination of certain functional categories can be addressed in
the relevant reliability standards.
Likes

0

Dislikes

0

Response
Michael Jones - National Grid USA - 1,3,5
Answer
Document Name
Comment
Should PRC-005 be applicable to Distribution Providers and the sub-set UFLS-only DP? For PRC-005, it may not be appropriate to
replace Distribution Providers with the more limiting “UFLS-only DP” applicability.
Likes

0

Dislikes

0

Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
None

Consideration of Comments
Project 2017-07 Alignment with Registration | December 2017

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Likes

0

Dislikes

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Response

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24

Standard Authorization Request (SAR) Form
Complete and please email this form, with
attachment(s) to: sarcomm@nerc.net

SAR Title:
Date Submitted:
SAR Requester

The North American Electric Reliability
Corporation (NERC) welcomes suggestions to
improve the reliability of the bulk power system
through improved Reliability Standards.

Requested information
Standards Alignment with Registration

Revised by Project 2017-07 Standards Alignment with Registration SAR Drafting Team
Stephen Wendling, Chair
Organization: American Transmission Company
Telephone:
(608) 877-8232
Email:
swendling@atcllc.com
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
Withdraw/retire an Existing Standard
Other (Please specify)
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
This project will align the Reliability Standards with the outcome of the Risk-Based Registration (RBR)
initiative.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
This project would modify Reliability Standards to be consistent with the FERC-approved changes to
registration as part of the RBR initiative.
Project Scope (Define the parameters of the proposed project):
This project will review and align Reliability Standards impacted by the RBR initiative.
Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification 1which includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g. research paper) to guide development of the Standard or definition):
This project will formally address any remaining edits to the Reliability Standards that are needed to
align the existing standards with the RBR initiatives. The edits include updates to the BAL, CIP, FAC, INT,
IRO, MOD, NUC, and TOP family of standards to remove the references to Purchasing-Selling Entities
Name:

The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please
attach pertinent information to this form before submittal to NERC.

1

1

Requested information
(PSEs) and Interchange Authorities (IAs); references to the Load-Serving Entity (LSEs) will be removed or
replaced by either the Distribution Provider (DP), the Balancing Authority (BA), or the appropriate
applicable entity. Additionally, the project will include adding Underfrequency Load Shedding (UFLS)only DPs to the Applicability Section of PRC-005 and PRC-006; and review the Applicability sections of
PRC-004 and PRC-008 and revise, as appropriate, to add UFLS-only DPs.
The clean-up effort of the standards can be categorized into the following:
1. Modifications to existing standards where the removal of the retired function may need
replacement by another function. For instance, Reliability Standard MOD-032-1 specifies certain
data from LSEs that may need to be provided by other functional entities going forward.
2. Modifications where the applicable entity and references may be removed. These updates may
be able to follow a similar process to the Paragraph 81 initiatives where standards are redlined
and posted for industry comment and ballot. A majority of the edits would simply remove
deregistered functional entities and their applicable requirements/references. The impacted
standards include the BAL, CIP, IRO, and TOP family of standards. Additionally PRC-005-1.1b and
PRC-006-003 will be updated to add UFLS-only DP to the Applicability Sections and a review of
the Applicability Sections of PRC-004-5(i) and PRC-008-0 to add, as appropriate, UFLS-only DP to
align with the post-RBR registration impacts.
3. Initiatives that can address RBR updates through the periodic review process. This would

include the INT-004-3.1 and NUC-001-3 standards. Rather than the Project 2017-07 making the
revisions the SDT could coordinate with the periodic review teams currently reviewing INT-0043.1 and NUC-001-3 so that any changes resulting from those periodic reviews, if any, may be
proposed at the same time after completion of each periodic review.

Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
No additional costs outside of the time and resources needed to serve on the SAR and Standard Drafting
Team.
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g. Dispersed Generation Resources):
None
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
Since LSE is being removed or replaced by either the Distribution Provider (DP), the Balancing Authority
(BA), or the appropriate Applicable Entity for the standards that need to be updated, those entities will
likely be best suited for the MOD and PRC updates.

2

Requested information
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
None
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so which standard(s) or project number(s)?
None
Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to

Enter
(yes/no)
Yes
Yes
Yes
Yes

Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted
to obtain industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.

2

3

Market Interface Principles
access commercially non-sensitive information that is required for compliance
with reliability standards.
Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
NPCC and SERC UFLS-only DP will be added to the Applicability Section of PRC-006 and will create a
variance of the following two Regional Standards:
PRC-006-NPCC-1
PRC-006-SERC-01
PRC-006-SERC-02

4

For Use by NERC Only
SAR Status Tracking (Check off as appropriate)
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC

Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document

Version History
Version

Date

Owner

Change Tracking

1

June 3, 2013

Revised

1

August 29, 2014

Standards Information Staff

Updated template

2

January X, 2017

Standards Information Staff

Revised

5

Standard Authorization Request (SAR) Form
Complete and please email this form, with
attachment(s) to: sarcomm@nerc.net

SAR Title:
Date Submitted:
SAR Requester

The North American Electric Reliability
Corporation (NERC) welcomes suggestions to
improve the reliability of the bulk power system
through improved Reliability Standards.

Requested information
Standards Alignment with Registration

NERC Standards StaffRevised by Project 2017-07 Standards Alignment with
Registration SAR Drafting Team
Stephen Wendling, Chair
Organization: NERCAmerican Transmission Company
Telephone:
(608) 877-8232
Email:
swendling@atcllc.com
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
Withdraw/retire an Existing Standard
Other (Please specify)
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
This project will align the Reliability Sstandards that are impacted bywith the outcome of the Risk-Based
Registration (RBR) initiative.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
This project aligns would modify Reliability Standards to be consistent with the FERC-approved changes
to registration as part of the RBR initiative.
Project Scope (Define the parameters of the proposed project):
This project will review and align Reliability standards Standards impacted by the RBR initiative.
Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification 1which includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g. research paper) to guide development of the Standard or definition):
This project will formally address any remaining edits to the Reliability standards Standards that are
needed to align the existing standards with the RBR initiatives. The edits include updates to the BAL,
Name:

The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please
attach pertinent information to this form before submittal to NERC.

1

1

Requested information
CIP, FAC, INT, IRO, MOD, NUC, and TOP family of standards to remove the references to PurchasingSelling Entities (PSEs) and Interchange Authorities (IAs); references to the Load-Serving Entity (LSEs) will
be removed or replaced by either the Distribution Provider (DP), or the Balancing Authority (BA), or the
appropriate applicable entity. Additionally, the project will include adding Underfrequency Load
Shedding (UFLS)-only DPs to the Applicability Section of PRC-005 and PRC-006; and review the
Applicability sections of PRC-004 PRC-005and PRC-008 will replace and revise, as appropriate, to add
UFLS-only DPs.the distribution provider with the Underfrequency Load Shedding (UFLS)-only DPs.
The clean-up effort of the standards can be categorized into the following:
1. Modifications to existing standards where the removal of the retired function may need
replacement by another function. Specifically, For instance, Reliability Standard MOD-032-1
specifies certain data from LSEs that may need to be provided by other functional entities going
forward. A SAR has been submitted to modify the MOD standards, and it would be posted with
the Alignment with Registration SAR.
2. Modifications where the applicable entity and references may be removed. These updates may
be able to follow a similar process to the Paragraph 81 initiatives where standards are redlined
and posted for industry comment and ballot. A majority of the edits would simply remove
deregistered functional entities and their applicable requirements/references. The impacted
standards include the BAL, CIP, IRO, and TOP family of standards. Additionally PRC-005-1.1b and
PRC-006-003 will be updated to replace add distribution providers with the more-limited UFLSonly DP to the Applicability Sections and a review of the Applicability Sections of PRC-004-5(i)
and PRC-008-0 to add, as appropriate, UFLS-only DP to align with the post-RBR registration
impacts.
3. Initiatives that can address RBR updates through the periodic review process. This would

include the INT-004-3.1 and NUC-001-3 standards. In other words, rRather than the Project
2017-07 making the revisions immediately, thisthe SDT could coordinate with information would
be provided to the periodic review teams currently reviewing INT-004-3.1 and NUC-001-3 so that
any changes resulting from those periodic reviews, if any, may be proposed at the same time
after completion of each periodic review.

Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
No additional costs outside of the time and resources needed to serve on the SAR and SC Standard
Drafting Tteam.
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g. Dispersed Generation Resources):
NANone
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
2

Requested information
Since LSE is being removed or replaced by either a the Distribution Provider (DP), or the Balancing
Authority (BA), or the appropriate Applicable Entity for the standards that need to be updated, those
entities will like likely be best suited for the MOD and PRC updates.
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
NANone
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so which standard(s) or project number(s)?
A separate SAR on the MOD standards was recently received that would be addressed by this
project.None
Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.

Enter
(yes/no)
Yes
Yes

Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted
to obtain industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.

2

3

Market Interface Principles
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Yes
Yes

Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
e.g. NPCC and
UFLS-only DP will be added to the Applicability Section of PRC-006 and will create a
SERC
variance of the following two Regional Standards:
PRC-006-NPCC-1
PRC-006-SERC-01
PRC-006-SERC-02

4

For Use by NERC Only
SAR Status Tracking (Check off as appropriate)
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC

Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document

Version History
Version

Date

Owner

Change Tracking

1

June 3, 2013

Revised

1

August 29, 2014

Standards Information Staff

Updated template

2

January X, 2017

Standards Information Staff

Revised

5

Unofficial Comment Form

Project 2017-07 Standards Alignment with Registration
Do not use this form for submitting comments. Use the electronic form to submit comments on Project
2017-07 Standards Alignment with Registration. The electronic form must be submitted by 8 p.m.
Eastern, Tuesday, January 9, 2018.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Standards
Developer, Laura Anderson (via email), or at 404-446-9671.
Background Information

On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North American
Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) Initiative in Docket No. RR15-4-000.
FERC approved the removal of two functional categories, Purchasing-Selling Entity (PSE) and Interchange
Authority (IA), from the NERC Compliance Registry due to the commercial nature of these categories
posing little or no risk to the reliability of the bulk power system.
FERC also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently approved on
compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria.
Several projects have addressed standards impacted by the RBR initiative since FERC approval; however,
there remain some Reliability Standards that require minor revisions so that they align with the post-RBR
registration impacts.
Project 2017-07 Standards Alignment with Registration is focused on making the tailored Reliability
Standards updates necessary to reflect the retirement of PSEs, IAs, and LSEs (as well as all of their
applicable references). This alignment includes three categories:
1. Modifications to existing standards where the removal of the retired function may need
replacement by another function. Specifically, Reliability Standard MOD-032-1 specifies certain
data from LSEs that may need to be provided by other functional entities going forward.
2. Modifications where the applicable entity and references may be removed. These updates may be
able to follow a similar process to the Paragraph 81 initiatives where standards are redlined and
posted for industry comment and ballot. A majority of the edits would simply remove
deregistered functional entities and their applicable requirements/references. Additionally PRC005 will be updated to replace Distribution Providers (DP) with the more-limited UFLS-only DP to
align with the post-RBR registration impacts.
3. Initiatives that can address RBR updates through the periodic review process. This would include
the INT-004 and NUC-001 standards. In other words, rather than making the revisions
immediately, this information would be provided to the periodic review teams currently reviewing

INT-004 and NUC-001 so that any changes resulting from those periodic reviews, if any, may be
proposed at the same time after completion of each periodic review.

Questions

1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR? If
not, please explain why you do not agree and, if possible, provide specific language revisions that
would make it acceptable to you.
Yes
No
Comments:
2. The SAR Drafting Team has merged the Project 2017-07 Standards Alignment with Registration
SAR and the MOD-032-1 SAR into a single SAR for this project. Do you agree with the merging of
the two SARs into a single SAR for Project 2017-07? If not, please explain why you do not agree
and, if possible, provide specific language revisions that would make it acceptable to you.
Yes
No
Comments:
3. If you have any other comments on this SAR that you haven’t already mentioned above, please
provide them here:
Comments:

Unofficial Comment Form
Project 2017-07 Standards Alignment with Registration | December 2017

2

Standards Announcement

Project 2017-07 Standards Alignment with Registration
Standards Authorization Request
Formal Comment Period Open through January 9, 2018
Now Available

An additional 30‐day formal comment period on the Standards Authorization Request (SAR) for 
Standards Alignment with Registration is open through 8 p.m. Eastern, Tuesday, January 9, 2018. 

Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments on the SAR. If you 
experience any difficulties using the electronic form, contact Nasheema Santos. The unofficial Word 
version of the comment form is posted on the project page. 


If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential 
error messages, or system lock‐out, contact NERC IT support directly at 
https://support.nerc.net/ (Monday – Friday, 8 a.m. ‐ 5 p.m. Eastern). 



Passwords expire every 6 months and must be reset. 



The SBS is not supported for use on mobile devices. 



Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try 
logging into their SBS accounts prior to the last day of a comment/ballot period. 

Next Steps

The drafting team will review all responses received during the comment period and determine the next 
steps of the project. 

For more information on the Standards Development Process, refer to the Standard Processes 
Manual. 

For more information or assistance, contact Standards Developer, Laura Anderson (via email) or at 
(404) 446‐9671. 
North American Electric Reliability Corporation 
3353 Peachtree Rd, NE 
Suite 600, North Tower 

Atlanta, GA 30326 
404‐446‐2560 | www.nerc.com 

Standards Announcement 
Project 2017‐07 Standards Alignment with Registration | December 11, 2017 

2

Comment Report
Project Name:

2017-07 Standards Alignment with Registration | Standards Authorization Request

Comment Period Start Date:

12/11/2017

Comment Period End Date:

1/9/2018

Associated Ballots:

There were 16 sets of responses, including comments from approximately 67 different people from approximately 51 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR? If not, please explain why you do not
agree and, if possible, provide specific language revisions that would make it acceptable to you.

2. The SAR Drafting Team has merged the Project 2017-07 Standards Alignment with Registration SAR and the MOD-032-1 SAR into a single
SAR for this project. Do you agree with the merging of the two SARs into a single SAR for Project 2017-07? If not, please explain why you do
not agree and, if possible, provide specific language revisions that would make it acceptable to you.

3. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:

Organization
Name
Southwest
Power Pool,
Inc. (RTO)

Duke Energy

ACES Power
Marketing

Entergy

Name

Charles
Yeung

Segment(s)

2

Colby Bellville 1,3,5,6

Jodirah Green 6

Julie Hall

5,6

Region

SPP RE

Group Name

SRC

FRCC,RF,SERC Duke Energy

NA - Not
Applicable

Group Member
Name

Group
Member
Segment(s)

Group Member
Region

Charles Yeung

SPP

2

SPP RE

Ben Li

IESO

2

NPCC

Greg Campoli

NYISO

2

NPCC

Lori Spence

MISO

2

MRO

Mark Holman

PJM

2

RF

Matt Goldberg

ISONE

1

NPCC

Doug Hils

Duke Energy

1

RF

Lee Schuster

Duke Energy

3

FRCC

Dale Goodwine

Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

ACES
Shari Heino
Standard
Collaborations

Entergy

Group
Member
Organization

Brazos
5
Electric Power
Cooperative,
Inc.

Texas RE

Greg Froehling

Rayburn
Country
Electric
Cooperative,
Inc.

Texas RE

John Shaver

Arizona
1
Electric Power
Cooperative,
Inc.

WECC

Paul Mehlhaff

Sunflower
1
Electric Power
Corporation

SPP RE

Kevin Lyons

Central Iowa
Power
Cooperative

1

MRO

Susan Sosbe

Wabash
Valley Power
Association

3

RF

Oliver Burke

Entergy 1
Entergy
Services, Inc.

SERC

Jamie Prater

Entergy

SERC

6

5

Southern
Marsha
Company Morgan
Southern
Company
Services, Inc.

Northeast
Power
Coordinating
Council

Ruida Shu

1,3,5,6

SERC

1,2,3,4,5,6,7,8,9,10 NPCC

Southern
Company

Katherine Prewitt Southern
Company
Services, Inc

1

SERC

Jennifer Sykes

Southern
Company
Generation
and Energy
Marketing

6

SERC

R Scott Moore

Alabama
Power
Company

3

SERC

William Shultz

Southern
Company
Generation

5

SERC

Northeast
Power
Coordinating
Council

10

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Wayne Sipperly

New York
Power
Authority

4

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian Robinson

Utility
Services

5

NPCC

Bruce Metruck

New York
Power
Authority

6

NPCC

Alan Adamson

New York
State
Reliability
Council

7

NPCC

Edward Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele Tondalo

UI

1

NPCC

Laura Mcleod

NB Power

1

NPCC

David
Ramkalawan

Ontario Power 5
Generation
Inc.

NPCC

RSC no
Guy V. Zito
Dominion and
ISO-NE

Quintin Lee

Southwest
Power Pool,
Inc. (RTO)

Shannon
Mickens

2

SPP RE

Eversource
Energy

1

NPCC

Paul Malozewski Hydro One
3
Networks, Inc.

NPCC

Helen Lainis

IESO

2

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael Jones

National Grid

3

NPCC

Greg Campoli

NYISO

2

NPCC

Sylvain Clermont Hydro Quebec 1

NPCC

Chantal Mazza

Hydro Quebec 2

NPCC

Silvia Mitchell

NextEra
6
Energy Florida Power
and Light Co.

NPCC

Michael Forte

Con Ed Consolidated
Edison

1

NPCC

Daniel Grinkevich Con Ed 1
Consolidated
Edison Co. of
New York

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Brian O'Boyle

Con Ed Consolidated
Edison

5

NPCC

Sean Cavote

PSEG

4

NPCC

2

SPP RE

Jeff McDiarmid

Southwest
2
Powr Pool Inc.

SPP RE

Louis Guidry

Cleco
Corporation

SPP RE

Tara Lightner

Sunflower
1
Electric Power
Corporation

SPP
Shannon Mickens Southwest
Standards
Power Pool
Inc.
Review Group

1,3,5,6

SPP RE

1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR? If not, please explain why you do not
agree and, if possible, provide specific language revisions that would make it acceptable to you.
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC
Answer

No

Document Name
Comment
The SRC understands the scope and objectives for this project. However, we seek more explanation to why this project needs to be moved forward at
this juncture given the Standards Efficiency Review (SER) which is intended to be a whole-sale look at the Standards. The changes in Project 2017-07
appear to have little impact on the state of reliability. We understand the deregistration of the LSE is prompting these changes, but the processes that
this SAR will change do not seem to be gravely impacted by that deregistration. Although the NERC standards that have been assigned to the LSE
were to ensure certain data and information are provided to reliability related processes in MOD-032, NERC should provide more evidence that there
was a problem in obtaining the information when the deregistration occurred.

Additionally, with some of the activity occurring regarding distributed energy resources and their impact on the BES, we believe it’s time to pause and be
sure we are able to get necessary data from DPs.

We suggest this project be put on hold pending the initial phase of the SER project which may better inform the scope of this proposal noting that this
project is a Low Prioirity in the 2018 RSDP.

Further, INT- 004 PSE requirements have already been allocated to the North American Energy Standards Board (NAESB) and filed with FERC as
NAESB Business Practice Standards. This already removed the responsibility for INT standards out of NERC into NAESB – so what is the risk to
reliability if the INT-004 requirements no longer have obligations on the PSE?

(note – Although IESO signs onto the overall consensus IRC comments, IESO does not support the comments in response to Question #1)
Likes

0

Dislikes

0

Response

Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer
Document Name
Comment

No

ERCOT agrees that the NERC Reliability Standards should be revised to remove references to functional entities that are no longer subject to
registration with NERC and to modify requirements to reallocate duties formerly assigned to these retired functions. However, ERCOT recommends that
all revisions—including those that could be addressed through later periodic review (i.e., the third category identified in the SAR)—be addressed as part
of this project. There are no efficiencies to be gained by leaving these issues for a future project, and this would only delay the needed clarifications.
Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
We agree with the need to review the alignment issue, but reserve judgment on the proposed changes to the affected standards.
Likes

0

Dislikes

0

Response

Jodirah Green - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standard Collaborations
Answer

Yes

Document Name
Comment
Yes, there is agreement with the proposed scope and objectives for Project 2017-07 described in the SAR. Since the functional categories have been
removed, updating all impacted standards is required to provide clarity to Registered Entities and Regional Entities.
Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 3,5
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ozan Ferrin - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Julie Hall - Entergy - 5,6, Group Name Entergy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10

Answer
Document Name
Comment
Texas RE appreciates the project to align the Reliability Standards with the Risk-Based Registration initiative. Texas RE agrees with adding
Underfrequency Load Shedding (UFLS) – only DPs to the applicability section of certain standards. Texas RE recommends the SAR drafting team also
review the requirements of those standards to determine whether UFLS-only DPs should be added to the requirement language of those standards to
ensure there are no reliability gaps.

Additionally, Texas RE suggests the SAR drafting team consider adding UFLS-only DPs to the applicability and requirement section of the following
standards:
·

EOP-004 – Add UFLS-only DPs as an entity with Reporting Responsibility in Attachment 1 to the following Event Types:

o Automatic firm load shedding ≥ 100 MW (via automatic undervoltage or underfrequency load shedding schemes, or RAS) – If the event
occurred, a UFLS-only DP should be expected to have reporting responsibility.
o Damage or destruction of a Facility - UFLS DPs should have reporting responsibilities since one of the last lines of reliability defense is
underfrequency relaying entities.
·
FAC-002 - FAC-002 needs to include UFLS-only DPs in the applicability section so new or materially-modified existing Facilities are coordinated
and studied appropriately. If FAC-002 does not include UFLS-only DPs, the UFLS-only DP may not coordinate and cooperate on studies with its
Transmission Planner or Planning Coordinator in accordance with FAC-002-2 Requirement R3.
·
IRO-010 – If the UFLS-only DPs are not included, they may not provide data to its Reliability Coordinator in accordance with Requirement
R3. This standard should include UFLS-only DP entities so that an RC can fully understand post-contingent projected system conditions (i.e. OPA and
RTA) that may recognize a possible underfrequency event and corresponding reaction to said event. If the RC does not have the UFLS information
available that analyses will be incomplete. The same issue applies to TOP-003.
·
COM-002 – If UFLS-only DP is not added to the applicability, that entity may not do the training required by COM-002-4 Requirement R3 or three
part communication as required by COM-002-4 Requirement R6. A UFLS-only DP may receive Operating Instructions to coordinate the re-energization
of underfrequency relay equipped load. That would indicate the need for proper communications between the appropriate parties. Furthermore, during
a Blackstart scenario the UFLS-only DP may be required to not re-energize load (through an Operating Instruction) to help coordinate the stabilization of
the grid during restoration.

Texas RE suggests modifying the SAR language to include these additional standards: “Additionally, the project will include adding Underfrequency
Load Shedding (UFLS)-only DPs to the Applicability Section and to the applicable Requirement language of COM-002, EOP-004, FAC-002, IRO-010,
TOP-003, PRC-005, PRC-006 and other standards noted during this project. The project will also include reviewing and revising adding UFLS-only DP
as appropriate to the Applicability Sections and Requirement language for PRC-004 and PRC-008 and any other Standard to which this issue may
apply.”
Likes

0

Dislikes
Response

0

2. The SAR Drafting Team has merged the Project 2017-07 Standards Alignment with Registration SAR and the MOD-032-1 SAR into a single
SAR for this project. Do you agree with the merging of the two SARs into a single SAR for Project 2017-07? If not, please explain why you do
not agree and, if possible, provide specific language revisions that would make it acceptable to you.
Jodirah Green - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standard Collaborations
Answer

Yes

Document Name
Comment
Yes, there is agreement with merging Project 2017-17 Standards Alignment with Registration and MOD-032-1 SARs. The removal of Load Serving
Entities (LSE) in the MOD-032-1 standard updates are in alignment with the removal of Purchasing-Selling Entity (PSE) and Interchange Authority (IA)
that requires minor revisions to their respected impacted standards to align with the post Risk Based Registration (RBR) impacts.
Likes

0

Dislikes

0

Response

Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Julie Hall - Entergy - 5,6, Group Name Entergy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ozan Ferrin - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC
Answer
Document Name
Comment
SRC has no opinion for this question
Likes

0

Dislikes
Response

0

3. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:
Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer
Document Name
Comment
No comments.
Likes

0

Dislikes

0

Response

Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC
Answer
Document Name
Comment
The IRC SRC asks whether this SAR is timely and whether there is truly a reliability gap if the changes are not made. We want to ensure that industry
resources are made available to address the most critical reliability issues first. Now that NERC has begun a SER of all NERC standards on an
expedited schedule, a wholesale re-look at all the standards; is it the best use of industry resources to begin another project that intends to open up the
same standards to the standards development process that may also be subject to revisions through the SER process?
As a matter of efficiency, since the NERC Standards Process potentially opens up a standard to changes that were not contemplated in the SAR and
can potentially extend the expected timelines to completion, should NERC explore alternative processes to reach industry consensus on projects such
as this which are intended to complement already accepted changes by the industry (de-register LSEs)?
Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer
Document Name
Comment

1. In the Detailed Description section, “appropriate applicable entity” should be clarified to indicate that only NERC-registered entities will be
potentially reassigned applicability.
2. Adding PRC-008-0 to the scope of this SAR is irrelevant as this Standard is governed by and was combined with PRC-005-2/PRC-005-6
effective 4/1/2015 and will be retired when the full Implementation Plan of PRC-005-6 is complete. (From IP: Standards PRC‐005 ‐1.1b, PR C‐
008‐0, PRC‐ 011‐ 0, and PRC‐ 017‐ 0 shall remain enforceable throughout the phased implementation period set forth in the PR C‐ 005 ‐2(i)
implementation plan, incorporated herein by reference, and shall be applicable to a registered entity’s Protection System Component
maintenance activities not yet transitioned to PRC‐005‐ 2(i) or its combined successor standards. Standards PRC‐ 005‐ 1.1b, PR C‐ 008‐0,
PRC‐011‐ 0, and PRC‐ 017‐ 0 shall be retired at midnight of March 31, 2027 or as otherwise m ade effective pur suant to the laws applicable to
such Electric Reliability Organization (ERO) governmental authorities; or, in those jurisdictions where no regulatory approval is required, at
midnight of March 31, 2027.).
3. Adding PRC-004-5(i) to the scope of this SAR is irrelevant as UFLS-only DP’s do not typically own BES interrupting devices that would operate
and therefore would not be obligated by this Standard’s Requirements R1 and R2. A UFLS-only DP who does own BES interrupting devices
would be additionally registered as a Transmission Owner (TO) as an owner of BES Elements and therefore this functional registration would
obligate the Standard’s applicability. Additionally, for a DP who owns a portion of a Composite Protection System, and would possibly be
notified by another entity of a BES interrupting device operation per Requirement R3, would be additionally registered as a UFLS-only DP per
the NERC Rules of Procedure, Appendix 5B: Registration Criteria for DP (A DP - Provides and operates the “wires” between the transmission
system and the end-use customer. For those end-use customers who are served at transmission voltages, the Transmission Owner also serves
as the Distribution Provider. Thus, the Distribution Provider is not defined by a specific voltage, but rather as performing the distribution function
at any voltage. Note: As provided in Section III.b.1 and Note 5 below, a Distribution Provider entity shall be an Underfrequency Load Shedding
(UFLS)-Only Distribution Provider if it is the responsible entity that owns, controls or operates UFLS Protection System(s) needed to implement
a required UFLS program designed for the protection of the BES, but does not meet any of the other registration criteria for a Distribution
Provider.)
4. A definition for Underfrequency Load Shedding (UFLS) should be added to the Glossary of Terms to add clarity to the meaning of this
term. Note that Undervoltage Load Shedding (UVLS) is currently in the Glossary of Terms (most recent definition effective 4/1/2017) but UFLS
is not. FERC NOPR under Docket No. RM11-20-000; October 20, 2011 provides a reference to the 2003 Blackout Report (U.S.-Canada Power
System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations at
92-93 (2004) (Blackout Report).) and an “explanation” of UFLS which could be used as a reference for developing a definition ([A]utomatic
under-frequency load-shedding (UFLS) is designed for use in extreme conditions to stabilize the balance between generation and load after an
electrical island has been formed, dropping enough load to allow frequency to stabilize within the island. All synchronous generators in North
America are designed to operate at 60 cycles per second (Hertz) and frequency reflects how well load and generation are balanced—if there is
more load than generation at any moment, frequency drops below 60 Hz, and it rises above that level if there is more generation than load. By
dropping load to match available generation within the island, UFLS is a safety net that helps to prevent the complete blackout of the island,
which allows faster system restoration afterward. UFLS is not effective if there is electrical instability or voltage collapse within the island.)
Likes

0

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Response

Jodirah Green - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standard Collaborations
Answer
Document Name
Comment

Thank you for the opportunity to provide comments.
Likes

0

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0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE dos not have additional comments.
Likes

0

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0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer
Document Name
Comment
It would be helpful if the SAR contained the list of standards that are affected by the proposed changes.
Likes

0

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0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
The SPP Standards Review Group (“SSRG”) generally supports the proposed scope and objectives for Project 2017-07 but reserves the right to provide
additional comments once the standards drafting team issues draft revised standards for industry review.

At this time, the SPPRG would recommend the standards drafting team consider two generalized comments when drafting the initial revised standards:
Regarding MOD-32-1, SPP continues to review the SAR’s proposal to replace “Load Serving Entity” with either a Distribution Provider, Balancing
Authority, or other “other applicable entity.” The SSRG understands “other applicable entity” to mean an applicable NERC Registered Entity, and this
interpretation appears to be consistent with the SAR’s cateogrization that “certain data from LSEs may need to be provided by other functional entities
going forward (emphasis added).” The standards drafting team must ensure that the NERC Registered Entity ultimately determined to be the
appropriate replacement for Load Serving Entity will be able to meet the current data reporting requirements identified in Attachment 1 of MOD-32-1. To
that end, the standard drafting team must also ensure the Planning Coordinator or Transmission Planner’s obligations will not be unreasonably
impacted by the replacement of the Load Serving Entity function.
Regarding proposed changes to PRC-005 and PRC-006 to add Underfrequency Load Shedding (UFLS)-only DP to the applicability section of the
standard(s), the SPPRG would recommend that the standards drafting team leverage pre-established language from existing standards, as appropriate,
when updating PRC-005 and PRC-006. For example, the language in current PRC-004-5(i) at Section 4.2.2 provides the description “[u]nderfrequency
load shedding (UFLS) that is intended to trip one or more BES elements” to clarify which sub-set of Distribution Provider facilities are included in the
standard. Such language could be utilized in Sections 4 of PRC-005 and PRC-006 to clarify the applicability to the UFLS-only DP. In other words, the
goal of updating PRC-005 and PRC-006 may be accomplished by utilizing current approved language related to the UFLS-only DP from from other
standards where appropriate.
Likes

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0

Consideration of Comments
Project Name:

2017-07 Standards Alignment with Registration | Standards Authorization Request

Comment Period Start Date: 12/11/2017
Comment Period End Date: 1/9/2018
Associated Ballots:

There were 16 sets of responses, including comments from approximately 67 different people from approximately 51 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Senior Director of Standards and
Education, Howard Gugel (via email) or at (404) 446‐9693.

Questions
1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR? If not, please explain why you do
not agree and, if possible, provide specific language revisions that would make it acceptable to you.
2. The SAR Drafting Team has merged the Project 2017-07 Standards Alignment with Registration SAR and the MOD-032-1 SAR into a
single SAR for this project. Do you agree with the merging of the two SARs into a single SAR for Project 2017-07? If not, please explain
why you do not agree and, if possible, provide specific language revisions that would make it acceptable to you.
3. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

2

Organization
Name

Name

Southwest Charles
Power Pool, Yeung
Inc. (RTO)

Duke Energy Colby
Bellville

ACES Power Jodirah
Marketing
Green

Segment(s)

2

1,3,5,6

6

Region

SPP RE

FRCC,RF,SERC

NA - Not
Applicable

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

Group Name

SRC

Duke Energy

ACES Standard
Collaborations

Group
Member
Name

Group
Group
Member
Member
Organization Segment(s)

Group
Member
Region

Charles
Yeung

SPP

2

SPP RE

Ben Li

IESO

2

NPCC

Greg Campoli NYISO

2

NPCC

Lori Spence

2

MRO

Mark Holman PJM

2

RF

Matt
Goldberg

ISONE

1

NPCC

Doug Hils

Duke Energy 1

MISO

RF

Lee Schuster Duke Energy 3

FRCC

Dale
Goodwine

Duke Energy 5

SERC

Greg Cecil

Duke Energy 6

RF

Shari Heino

Brazos
5
Electric
Power
Cooperative,
Inc.

Texas RE

Greg
Froehling

Rayburn
6
Country
Electric
Cooperative,
Inc.

Texas RE

3

John Shaver

Entergy

Julie Hall

5,6

Entergy

Arizona
1
Electric
Power
Cooperative,
Inc.

Paul Mehlhaff Sunflower
1
Electric
Power
Corporation

SPP RE

Kevin Lyons

MRO

Central Iowa 1
Power
Cooperative

Susan Sosbe Wabash
3
Valley Power
Association

RF

Oliver Burke

SERC

Entergy 1
Entergy
Services, Inc.

Jamie Prater Entergy
Southern
Marsha
Company - Morgan
Southern
Company
Services, Inc.

1,3,5,6

SERC

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

Southern Company

WECC

5

SERC

Katherine
Prewitt

Southern
1
Company
Services, Inc

SERC

Jennifer
Sykes

Southern
Company
Generation
and Energy
Marketing

SERC

6

4

Northeast
Ruida Shu 1,2,3,4,5,6,7,8,9,10 NPCC
Power
Coordinating
Council

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

R Scott
Moore

Alabama
Power
Company

3

SERC

William
Shultz

Southern
Company
Generation

5

SERC

RSC no Dominion and Guy V. Zito
ISO-NE

Northeast
10
Power
Coordinating
Council

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Wayne
Sipperly

New York
Power
Authority

4

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian
Robinson

Utility
Services

5

NPCC

Bruce
Metruck

New York
Power
Authority

6

NPCC

Alan
Adamson

New York
State
Reliability
Council

7

NPCC

5

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

Edward
Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele
Tondalo

UI

1

NPCC

Laura Mcleod NB Power

1

NPCC

David
Ontario
Ramkalawan Power
Generation
Inc.

5

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

Paul
Malozewski

Hydro One
Networks,
Inc.

3

NPCC

Helen Lainis

IESO

2

NPCC

Michael
Schiavone

National
Grid

1

NPCC

Michael Jones National
Grid

3

NPCC

Greg Campoli NYISO

2

NPCC

Sylvain
Clermont

1

NPCC

Hydro
Quebec

6

Chantal
Mazza

Hydro
Quebec

2

NPCC

6

NPCC

Michael Forte Con Ed 1
Consolidated
Edison

NPCC

Daniel
Grinkevich

Con Ed 1
Consolidated
Edison Co. of
New York

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Brian O'Boyle Con Ed 5
Consolidated
Edison

NPCC

Sean Cavote

Silvia Mitchell NextEra
Energy Florida
Power and
Light Co.

Southwest Shannon
Power Pool, Mickens
Inc. (RTO)

2

SPP RE

SPP Standards Review Shannon
Group
Mickens
Jeff
McDiarmid

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

PSEG

4

NPCC

Southwest
Power Pool
Inc.

2

SPP RE

Southwest
Powr Pool
Inc.

2

SPP RE

7

Louis Guidry

Cleco
1,3,5,6
Corporation

Tara Lightner Sunflower
1
Electric
Power
Corporation

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

SPP RE
SPP RE

8

1. Do you agree with the proposed scope and objectives for Project 2017-07 described in the SAR? If not, please explain why you do not
agree and, if possible, provide specific language revisions that would make it acceptable to you.
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC
Answer

No

Document Name
Comment
The SRC understands the scope and objectives for this project. However, we seek more explanation to why this project needs to be moved
forward at this juncture given the Standards Efficiency Review (SER) which is intended to be a whole-sale look at the Standards. The changes
in Project 2017-07 appear to have little impact on the state of reliability. We understand the deregistration of the LSE is prompting these
changes, but the processes that this SAR will change do not seem to be gravely impacted by that deregistration. Although the NERC standards
that have been assigned to the LSE were to ensure certain data and information are provided to reliability related processes in MOD-032,
NERC should provide more evidence that there was a problem in obtaining the information when the deregistration occurred.
Additionally, with some of the activity occurring regarding distributed energy resources and their impact on the BES, we believe it’s time to
pause and be sure we are able to get necessary data from DPs.
We suggest this project be put on hold pending the initial phase of the SER project which may better inform the scope of this proposal noting
that this project is a Low Prioirity in the 2018 RSDP.
Further, INT- 004 PSE requirements have already been allocated to the North American Energy Standards Board (NAESB) and filed with FERC
as NAESB Business Practice Standards. This already removed the responsibility for INT standards out of NERC into NAESB – so what is the risk
to reliability if the INT-004 requirements no longer have obligations on the PSE?
(note – Although IESO signs onto the overall consensus IRC comments, IESO does not support the comments in response to Question #1)
Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

9

Response
Thank you for your comments. Project 2017-07 is a review and alignment effort resulting from the RBR Initiative project and would modify
Reliability Standards to be consistent with the FERC-approved changes.
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer

No

Document Name
Comment
ERCOT agrees that the NERC Reliability Standards should be revised to remove references to functional entities that are no longer subject to
registration with NERC and to modify requirements to reallocate duties formerly assigned to these retired functions. However, ERCOT
recommends that all revisions—including those that could be addressed through later periodic review (i.e., the third category identified in the
SAR)—be addressed as part of this project. There are no efficiencies to be gained by leaving these issues for a future project, and this would
only delay the needed clarifications.
Likes

0

Dislikes

0

Response
Thank you for your comments. Project 2017-07 is a review and alignment effort resulting from the RBR Initiative project and would modify
Reliability Standards to be consistent with the FERC-approved changes. The future drafting team for this project will review and determine if
revisions falling within Category Number 3 in the Detailed Description Section of the draft SAR are made more efficiently within the periodic
reviews or by the Standards Alignment with Registration drafting team. The SAR Drafting Team has been involved in collaborative efforts with
the current INT Review Team, as well as the current NUC Review Team. It is anticipated that both periodic review efforts will have completed
prior to commencement of the future drafting of the Standards Alignment with Registration drafting effort, and the final recommendations
from the periodic reviews will help the future Drafting Team determine the proper course to take in revisions to the INT and NUC standards.
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

10

Document Name
Comment
We agree with the need to review the alignment issue, but reserve judgment on the proposed changes to the affected standards.
Likes

0

Dislikes

0

Response
Thank you for your comment.
Jodirah Green - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standard Collaborations
Answer

Yes

Document Name
Comment
Yes, there is agreement with the proposed scope and objectives for Project 2017-07 described in the SAR. Since the functional categories
have been removed, updating all impacted standards is required to provide clarity to Registered Entities and Regional Entities.
Likes

0

Dislikes

0

Response
Thank you for your comment.
Thomas Foltz - AEP - 3,5
Answer

Yes

Document Name
Comment
Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

11

Likes

0

Dislikes

0

Response
Andrew Gallo - Austin Energy - 1,3,4,5,6
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Ozan Ferrin - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

12

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Julie Hall - Entergy - 5,6, Group Name Entergy
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

13

Dislikes

0

Response
Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer

Yes

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

14

Document Name
Comment
Likes

0

Dislikes

0

Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

15

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE appreciates the project to align the Reliability Standards with the Risk-Based Registration initiative. Texas RE agrees with adding
Underfrequency Load Shedding (UFLS) – only DPs to the applicability section of certain standards. Texas RE recommends the SAR drafting
team also review the requirements of those standards to determine whether UFLS-only DPs should be added to the requirement language of
those standards to ensure there are no reliability gaps.
Additionally, Texas RE suggests the SAR drafting team consider adding UFLS-only DPs to the applicability and requirement section of the
following standards:
·

EOP-004 – Add UFLS-only DPs as an entity with Reporting Responsibility in Attachment 1 to the following Event Types:

o Automatic firm load shedding ≥ 100 MW (via automatic undervoltage or underfrequency load shedding schemes, or RAS) – If the event
occurred, a UFLS-only DP should be expected to have reporting responsibility.
o Damage or destruction of a Facility - UFLS DPs should have reporting responsibilities since one of the last lines of reliability defense is
underfrequency relaying entities.
·
FAC-002 - FAC-002 needs to include UFLS-only DPs in the applicability section so new or materially-modified existing Facilities are
coordinated and studied appropriately. If FAC-002 does not include UFLS-only DPs, the UFLS-only DP may not coordinate and cooperate on
studies with its Transmission Planner or Planning Coordinator in accordance with FAC-002-2 Requirement R3.
·
IRO-010 – If the UFLS-only DPs are not included, they may not provide data to its Reliability Coordinator in accordance with
Requirement R3. This standard should include UFLS-only DP entities so that an RC can fully understand post-contingent projected system

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

16

conditions (i.e. OPA and RTA) that may recognize a possible underfrequency event and corresponding reaction to said event. If the RC does
not have the UFLS information available that analyses will be incomplete. The same issue applies to TOP-003.
·
COM-002 – If UFLS-only DP is not added to the applicability, that entity may not do the training required by COM-002-4 Requirement R3
or three part communication as required by COM-002-4 Requirement R6. A UFLS-only DP may receive Operating Instructions to coordinate
the re-energization of underfrequency relay equipped load. That would indicate the need for proper communications between the
appropriate parties. Furthermore, during a Blackstart scenario the UFLS-only DP may be required to not re-energize load (through an
Operating Instruction) to help coordinate the stabilization of the grid during restoration.
Texas RE suggests modifying the SAR language to include these additional standards: “Additionally, the project will include adding
Underfrequency Load Shedding (UFLS)-only DPs to the Applicability Section and to the applicable Requirement language of COM-002, EOP004, FAC-002, IRO-010, TOP-003, PRC-005, PRC-006 and other standards noted during this project. The project will also include reviewing and
revising adding UFLS-only DP as appropriate to the Applicability Sections and Requirement language for PRC-004 and PRC-008 and any other
Standard to which this issue may apply.”
Likes

0

Dislikes

0

Response
Thank you for your comments. Your comments to include Reliability Standards other than those referenced in the draft SAR would be outside
the scope of this project. Project 2017-07 is a review and alignment effort resulting from the RBR Initiative project and would modify
Reliability Standards to be consistent with the FERC-approved changes.

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

17

2. The SAR Drafting Team has merged the Project 2017-07 Standards Alignment with Registration SAR and the MOD-032-1 SAR into a single
SAR for this project. Do you agree with the merging of the two SARs into a single SAR for Project 2017-07? If not, please explain why you
do not agree and, if possible, provide specific language revisions that would make it acceptable to you.
Jodirah Green - ACES Power Marketing - 6 - NA - Not Applicable, Group Name ACES Standard Collaborations
Answer

Yes

Document Name
Comment
Yes, there is agreement with merging Project 2017-17 Standards Alignment with Registration and MOD-032-1 SARs. The removal of Load
Serving Entities (LSE) in the MOD-032-1 standard updates are in alignment with the removal of Purchasing-Selling Entity (PSE) and
Interchange Authority (IA) that requires minor revisions to their respected impacted standards to align with the post Risk Based Registration
(RBR) impacts.
Likes

0

Dislikes

0

Response
Thank you for your comment.
Marsha Morgan - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

18

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer

Yes

Document Name
Comment
Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

19

Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

20

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Julie Hall - Entergy - 5,6, Group Name Entergy
Answer

Yes

Document Name
Comment

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

21

Likes

0

Dislikes

0

Response
Ozan Ferrin - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Andrew Gallo - Austin Energy - 1,3,4,5,6
Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

22

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thomas Foltz - AEP - 3,5
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

23

Dislikes

0

Response
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC
Answer
Document Name
Comment
SRC has no opinion for this question
Likes

0

Dislikes

0

Response

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

24

3. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:
Jeanne Kurzynowski - CMS Energy - Consumers Energy Company - 1,3,4,5 - RF
Answer
Document Name
Comment
No comments.
Likes

0

Dislikes

0

Response
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC
Answer
Document Name
Comment
The IRC SRC asks whether this SAR is timely and whether there is truly a reliability gap if the changes are not made. We want to ensure that
industry resources are made available to address the most critical reliability issues first. Now that NERC has begun a SER of all NERC standards
on an expedited schedule, a wholesale re-look at all the standards; is it the best use of industry resources to begin another project that
intends to open up the same standards to the standards development process that may also be subject to revisions through the SER process?
As a matter of efficiency, since the NERC Standards Process potentially opens up a standard to changes that were not contemplated in the
SAR and can potentially extend the expected timelines to completion, should NERC explore alternative processes to reach industry consensus
on projects such as this which are intended to complement already accepted changes by the industry (de-register LSEs)?

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

25

Likes

0

Dislikes

0

Response
Thank you for your comments. The SAR drafting team believes it is appropriate to address those issues at this time and as part of a dedicated, standalone effort.

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer
Document Name
Comment
1.

In the Detailed Description section, “appropriate applicable entity” should be clarified to indicate that only NERC-registered entities
will be potentially reassigned applicability.

2.

Adding PRC-008-0 to the scope of this SAR is irrelevant as this Standard is governed by and was combined with PRC-005-2/PRC-005-6
effective 4/1/2015 and will be retired when the full Implementation Plan of PRC-005-6 is complete. (From IP: Standards PRC‐005‐1.1b,
PRC‐008‐0, PRC‐011‐0, and PRC‐017‐0 shall remain enforceable throughout the phased implementation period set forth in the PRC‐
005‐2(i) implementation plan, incorporated herein by reference, and shall be applicable to a registered entity’s Protection System
Component maintenance activities not yet transitioned to PRC‐005‐2(i) or its combined successor standards. Standards PRC‐005‐1.1b,
PRC‐008‐0, PRC‐011‐0, and PRC‐017‐0 shall be retired at midnight of March 31, 2027 or as otherwise made effective pursuant to the
laws applicable to such Electric Reliability Organization (ERO) governmental authorities; or, in those jurisdictions where no regulatory
approval is required, at midnight of March 31, 2027.).

3.

Adding PRC-004-5(i) to the scope of this SAR is irrelevant as UFLS-only DP’s do not typically own BES interrupting devices that would
operate and therefore would not be obligated by this Standard’s Requirements R1 and R2. A UFLS-only DP who does own BES
interrupting devices would be additionally registered as a Transmission Owner (TO) as an owner of BES Elements and therefore this
functional registration would obligate the Standard’s applicability. Additionally, for a DP who owns a portion of a Composite
Protection System, and would possibly be notified by another entity of a BES interrupting device operation per Requirement R3, would
be additionally registered as a UFLS-only DP per the NERC Rules of Procedure, Appendix 5B: Registration Criteria for DP (A DP Provides and operates the “wires” between the transmission system and the end-use customer. For those end-use customers who are
served at transmission voltages, the Transmission Owner also serves as the Distribution Provider. Thus, the Distribution Provider is not

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

26

defined by a specific voltage, but rather as performing the distribution function at any voltage. Note: As provided in Section III.b.1 and
Note 5 below, a Distribution Provider entity shall be an Underfrequency Load Shedding (UFLS)-Only Distribution Provider if it is the
responsible entity that owns, controls or operates UFLS Protection System(s) needed to implement a required UFLS program designed
for the protection of the BES, but does not meet any of the other registration criteria for a Distribution Provider.)
4.

A definition for Underfrequency Load Shedding (UFLS) should be added to the Glossary of Terms to add clarity to the meaning of this
term. Note that Undervoltage Load Shedding (UVLS) is currently in the Glossary of Terms (most recent definition effective 4/1/2017)
but UFLS is not. FERC NOPR under Docket No. RM11-20-000; October 20, 2011 provides a reference to the 2003 Blackout Report
(U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes
and Recommendations at 92-93 (2004) (Blackout Report).) and an “explanation” of UFLS which could be used as a reference for
developing a definition ([A]utomatic under-frequency load-shedding (UFLS) is designed for use in extreme conditions to stabilize the
balance between generation and load after an electrical island has been formed, dropping enough load to allow frequency to stabilize
within the island. All synchronous generators in North America are designed to operate at 60 cycles per second (Hertz) and frequency
reflects how well load and generation are balanced—if there is more load than generation at any moment, frequency drops below 60
Hz, and it rises above that level if there is more generation than load. By dropping load to match available generation within the island,
UFLS is a safety net that helps to prevent the complete blackout of the island, which allows faster system restoration afterward. UFLS is
not effective if there is electrical instability or voltage collapse within the island.)

Likes

0

Dislikes

0

Response
Thank you for your comments.
1. The SAR Drafting Team agrees and has made the clarifying revision to the SAR.
2. The SAR Drafting Team agrees and has removed PRC-008-0 from the SAR.
3. The SAR Drafting Team agrees and has removed PRC-004-5(i) from the SAR.
4. The SAR Drafting Team has held discussions to proposing to define UFLS for the NERC Glossary of Terms. The SAR Drafting Team has added
the following language to the draft SAR: “In addition, the project will consider whether to include a definition for UFLS into the NERC
Glossary of Terms.”

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

27

Answer
Document Name
Comment
Thank you for the opportunity to provide comments.
Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE dos not have additional comments.
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no Dominion and ISO-NE
Answer
Document Name
Comment
Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

28

It would be helpful if the SAR contained the list of standards that are affected by the proposed changes.
Likes

0

Dislikes

0

Response
Thank you for your comment. The family of standards are contained within the SAR.
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
The SPP Standards Review Group (“SSRG”) generally supports the proposed scope and objectives for Project 2017-07 but reserves the right to
provide additional comments once the standards drafting team issues draft revised standards for industry review.
At this time, the SPPRG would recommend the standards drafting team consider two generalized comments when drafting the initial revised
standards:
Regarding MOD-32-1, SPP continues to review the SAR’s proposal to replace “Load Serving Entity” with either a Distribution Provider,
Balancing Authority, or other “other applicable entity.” The SSRG understands “other applicable entity” to mean an applicable NERC
Registered Entity, and this interpretation appears to be consistent with the SAR’s cateogrization that “certain data from LSEs may need to be
provided by other functional entities going forward (emphasis added).” The standards drafting team must ensure that the NERC Registered
Entity ultimately determined to be the appropriate replacement for Load Serving Entity will be able to meet the current data reporting
requirements identified in Attachment 1 of MOD-32-1. To that end, the standard drafting team must also ensure the Planning Coordinator or
Transmission Planner’s obligations will not be unreasonably impacted by the replacement of the Load Serving Entity function.
Regarding proposed changes to PRC-005 and PRC-006 to add Underfrequency Load Shedding (UFLS)-only DP to the applicability section of the
standard(s), the SPPRG would recommend that the standards drafting team leverage pre-established language from existing standards, as
appropriate, when updating PRC-005 and PRC-006. For example, the language in current PRC-004-5(i) at Section 4.2.2 provides the
description “[u]nderfrequency load shedding (UFLS) that is intended to trip one or more BES elements” to clarify which sub-set of Distribution
Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

29

Provider facilities are included in the standard. Such language could be utilized in Sections 4 of PRC-005 and PRC-006 to clarify the
applicability to the UFLS-only DP. In other words, the goal of updating PRC-005 and PRC-006 may be accomplished by utilizing current
approved language related to the UFLS-only DP from from other standards where appropriate.
Likes

0

Dislikes

0

Response
Thank you for your comment. The SAR Drafting Team agrees and has made the clarifying revision of NERC Registered Entity to the SAR. The
language suggestion for PRC-005 and PRC-006 is outside of the scope of the SAR Drafting Team. The SAR Drafting Team will forward the
suggestion to the future drafting team.

Consideration of Comments
Project 2017-07 Alignment with Registration | February 2018

30

Standard Authorization Request (SAR) Form
Complete and please email this form, with
attachment(s) to: sarcomm@nerc.net

SAR Title:
Date Submitted:
SAR Requester

The North American Electric Reliability
Corporation (NERC) welcomes suggestions to
improve the reliability of the bulk power system
through improved Reliability Standards.

Requested information
Standards Alignment with Registration

Revised by Project 2017-07 Standards Alignment with Registration SAR Drafting Team
Stephen Wendling, Chair
Organization: American Transmission Company
Telephone:
(608) 877-8232
Email:
swendling@atcllc.com
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
Withdraw/retire an Existing Standard
Other (Please specify)
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
This project will align the Reliability Standards with the outcome of the Risk-Based Registration (RBR)
initiative.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
This project would modify Reliability Standards to be consistent with the FERC-approved changes to
registration as part of the RBR initiative.
Project Scope (Define the parameters of the proposed project):
This project will review and align Reliability Standards impacted by the RBR initiative.
Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification 1which includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g. research paper) to guide development of the Standard or definition):
This project will formally address any remaining edits to the Reliability Standards that are needed to
align the existing standards with the RBR initiatives. The edits include updates to the BAL, CIP, FAC, INT,
IRO, MOD, NUC, and TOP family of standards to remove the references to Purchasing-Selling Entities
Name:

The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please
attach pertinent information to this form before submittal to NERC.

1

1

Requested information
(PSEs) and Interchange Authorities (IAs); references to the Load-Serving Entity (LSEs) will be removed or
replaced by the appropriate functional entity. The project will include adding Underfrequency Load
Shedding (UFLS)-only Distribution Providers (DPs) to the Applicability section of PRC-005 and PRC-006
per NERC registration criteria. Additionally, the project will consider whether to include a definition for
UFLS into the NERC Glossary of Terms, as well as review the standards to ensure consistent use of the
term Planning Coordinator.
The clean-up effort of the standards can be categorized into the following:
1. Modifications to existing standards where the removal of the retired function may need
replacement by another function. For instance, Reliability Standard MOD-032-1 specifies certain
data from LSEs that may need to be provided by other functional entities going forward.
2. Modifications where the applicable entity and references may be removed. These updates may
be able to follow a similar process to the Paragraph 81 initiatives where standards are redlined
and posted for industry comment and ballot. A majority of the edits would simply remove
deregistered functional entities and their applicable requirements/references. The impacted
standards include the BAL, CIP, IRO, and TOP family of standards. Additionally, PRC-005 and
PRC-006 will be updated to add UFLS-only DP to the Applicability sections.
3. Initiatives that can address RBR updates through the periodic review process. The 2017-07 SAR

drafting team should consider whether it or the periodic review teams currently reviewing those
standards should make the necessary revisions.

Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
No additional costs outside of the time and resources needed to serve on the SAR and Standard Drafting
Team.
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g. Dispersed Generation Resources):
None
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
Since LSE is being removed or replaced by either the Distribution Provider (DP), the Balancing Authority
(BA), or the appropriate Applicable Entity for the standards that need to be updated, those entities will
likely be best suited for the MOD and PRC updates.
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
None

Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted
to obtain industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.

2

2

Requested information
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so which standard(s) or project number(s)?
None
Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Enter
(yes/no)
Yes
Yes
Yes
Yes

3

Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
NPCC and SERC Regional Reliability Standards:
PRC-006-NPCC-1
PRC-006-SERC-01
PRC-006-SERC-02

4

For Use by NERC Only
SAR Status Tracking (Check off as appropriate)
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC

Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document

Version History
Version

Date

Owner

Change Tracking

1

June 3, 2013

Revised

1

August 29, 2014

Standards Information Staff

Updated template

2

December 11,
2017

Standards Information Staff

Revised

3

February 1, 2018

Standards Information Staff

Revised

5

Standard Authorization Request (SAR) Form
Complete and please email this form, with
attachment(s) to: sarcomm@nerc.net

SAR Title:
Date Submitted:
SAR Requester

The North American Electric Reliability
Corporation (NERC) welcomes suggestions to
improve the reliability of the bulk power system
through improved Reliability Standards.

Requested information
Standards Alignment with Registration

Revised by Project 2017-07 Standards Alignment with Registration SAR Drafting Team
Stephen Wendling, Chair
Organization: American Transmission Company
Telephone:
(608) 877-8232
Email:
swendling@atcllc.com
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
Withdraw/retire an Existing Standard
Other (Please specify)
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
This project will align the Reliability Standards with the outcome of the Risk-Based Registration (RBR)
initiative.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
This project would modify Reliability Standards to be consistent with the FERC-approved changes to
registration as part of the RBR initiative.
Project Scope (Define the parameters of the proposed project):
This project will review and align Reliability Standards impacted by the RBR initiative.
Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification 1which includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g. research paper) to guide development of the Standard or definition):
This project will formally address any remaining edits to the Reliability Standards that are needed to
align the existing standards with the RBR initiatives. The edits include updates to the BAL, CIP, FAC, INT,
IRO, MOD, NUC, and TOP family of standards to remove the references to Purchasing-Selling Entities
Name:

The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please
attach pertinent information to this form before submittal to NERC.

1

1

Requested information
(PSEs) and Interchange Authorities (IAs); references to the Load-Serving Entity (LSEs) will be removed or
replaced by either the Distribution Provider (DP), the Balancing Authority (BA), or the appropriate
functional applicable entity. Additionally, tThe project will include adding Underfrequency Load
Shedding (UFLS)-only Distribution Providers (DPs) to the Applicability Section section of PRC-005 and
PRC-006 per NERC registration criteria.; and review the Applicability sections of PRC-004 and PRC-008
and revise, as appropriate, to add UFLS-only DPs. Additionally, the project will consider whether to
include a definition for UFLS into the NERC Glossary of Terms, as well as review the standards to ensure
consistent use of the term Planning Coordinator.
The clean-up effort of the standards can be categorized into the following:
1. Modifications to existing standards where the removal of the retired function may need
replacement by another function. For instance, Reliability Standard MOD-032-1 specifies certain
data from LSEs that may need to be provided by other functional entities going forward.
2. Modifications where the applicable entity and references may be removed. These updates may
be able to follow a similar process to the Paragraph 81 initiatives where standards are redlined
and posted for industry comment and ballot. A majority of the edits would simply remove
deregistered functional entities and their applicable requirements/references. The impacted
standards include the BAL, CIP, IRO, and TOP family of standards. Additionally, PRC-005-1.1b
and PRC-006-003 will be updated to add UFLS-only DP to the Applicability Sectionssections. and
a review of the Applicability Sections of PRC-004-5(i) and PRC-008-0 to add, as appropriate,
UFLS-only DP to align with the post-RBR registration impacts.
3. Initiatives that can address RBR updates through the periodic review process. The 2017-07 SAR

drafting team should consider whether it or the periodic review teams currently reviewing those
standards should make the necessary revisions. This would include the INT-004-3.1 and NUC001-3 standards. Rather than the Project 2017-07 making the revisions the SDT could coordinate
with the periodic review teams currently reviewing INT-004-3.1 and NUC-001-3 so that any
changes resulting from those periodic reviews, if any, may be proposed at the same time after
completion of each periodic review.

Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
No additional costs outside of the time and resources needed to serve on the SAR and Standard Drafting
Team.
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g. Dispersed Generation Resources):
None
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
2

Requested information
Since LSE is being removed or replaced by either the Distribution Provider (DP), the Balancing Authority
(BA), or the appropriate Applicable Entity for the standards that need to be updated, those entities will
likely be best suited for the MOD and PRC updates.
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
None
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so which standard(s) or project number(s)?
None
Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Market Interface Principles
Does the proposed standard development project comply with all of the following
Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.

Enter
(yes/no)
Yes
Yes
Yes

Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted
to obtain industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.

2

3

Market Interface Principles
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Yes

Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
NPCC and SERC UFLS-only DP will be added to the Applicability Section of PRC-006 and will create a
variance of the following two Regional Reliability Standards:
PRC-006-NPCC-1
PRC-006-SERC-01
PRC-006-SERC-02

4

For Use by NERC Only
SAR Status Tracking (Check off as appropriate)
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC

Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document

Version History
Version

Date

Owner

Change Tracking

1

June 3, 2013

Revised

1

August 29, 2014

Standards Information Staff

Updated template

2

January
XDecember 11,
2017

Standards Information Staff

Revised

3

February 1, 2018

Standards Information Staff

Revised

5

Unofficial Comment Form

Project 2017-07 Standards Alignment with Registration
Do not use this form for submitting comments. Use the electronic form to submit comments on the
revised Standards Authorization Request for Project 2017-07 Standards Alignment with Registration. The
electronic form must be submitted by 8 p.m. Eastern, Friday, March 2, 2018.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Standards
Developer, Laura Anderson (via email), or at 404-446-9671.
Background Information

On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North American
Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) Initiative in Docket No. RR15-4-000.
FERC approved the removal of two functional categories, Purchasing-Selling Entity (PSE) and Interchange
Authority (IA), from the NERC Compliance Registry due to the commercial nature of these categories
posing little or no risk to the reliability of the bulk power system.
FERC also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently approved on
compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria.
Several projects have addressed standards impacted by the RBR initiative since FERC approval; however,
there remain some Reliability Standards that require minor revisions so that they align with the post-RBR
registration impacts.
Project 2017-07 Standards Alignment with Registration is focused on making the tailored Reliability
Standards updates necessary to reflect the retirement of PSEs, IAs, and LSEs (as well as all of their
applicable references). This alignment includes three categories:
1. Modifications to existing standards where the removal of the retired function may need
replacement by another function. Specifically, Reliability Standard MOD-032-1 specifies certain
data from LSEs that may need to be provided by other functional entities going forward.
2. Modifications where the applicable entity and references may be removed. These updates may be
able to follow a similar process to the Paragraph 81 initiatives where standards are redlined and
posted for industry comment and ballot. A majority of the edits would simply remove
deregistered functional entities and their applicable requirements/references. Additionally, PRC005 and PRC-006 will be updated to add UFLS-only DP to the Applicability sections.
3. Initiatives that can address RBR updates through the periodic review process. The 2017-07
Standards Authorization Request (SAR) drafting team should consider whether it or the periodic
review teams currently reviewing those standards should make the necessary revisions.
Additionally, the project will consider whether to include a definition for UFLS into the NERC Glossary of
Terms, as well as reviewing the standards to ensure consistent use of the term Planning Coordinator.

Questions

1. The SAR drafting team added “Additionally, the project will consider whether to include a
definition for UFLS into the NERC Glossary of Terms, as well as review the standards to ensure
consistent use of the term Planning Coordinator.” Do you agree the project should consider
including a definition for UFLS into the NERC Glossary of Terms and reviewing the standards to
ensure consistent use of the term Planning Coordinator? If not, please explain why you do not
agree and, if possible, provide specific language revisions that would make it acceptable to you.
Yes
No
Comments:
2. Project 2017-07 is a review and alignment effort resulting from the RBR Initiative project and

would modify Reliability Standards to be consistent with the FERC-approved changes; as such, the
SAR drafting team has removed references to PRC-004 and PRC-008 as being out of scope for this
project. Do you agree that references to PRC-004 and PRC-008 should be removed from the SAR?
If not, please explain why you do not agree and, if possible, provide specific language revisions
that would make it acceptable to you.
Yes
No
Comments:

3. If you have any other comments on this SAR that you haven’t already mentioned above, please
provide them here:
Comments:

Unofficial Comment Form
Project 2017-07 Standards Alignment with Registration | February 2018

2

Standards Announcement

Project 2017-07 Standards Alignment with Registration
Standards Authorization Request
Formal Comment Period Open through March 2, 2018
Now Available

An additional 30-day formal comment period on the Standards Authorization Request (SAR) for
Standards Alignment with Registration is open through 8 p.m. Eastern, Friday, March 2, 2018.
Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments on the SAR. If you
experience any difficulties using the electronic form, contact Nasheema Santos. The unofficial Word
version of the comment form is posted on the project page.


If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).



Passwords expire every 6 months and must be reset.



The SBS is not supported for use on mobile devices.



Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The drafting team will review all responses received during the comment period and determine the next
steps of the project.
For more information on the Standards Development Process, refer to the Standard Processes
Manual.
For more information or assistance, contact Standards Developer, Laura Anderson (via email) or at
(404) 446-9671.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower

Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement
Project 2017-07 Standards Alignment with Registration | December 11, 2017

2

Comment Report
Project Name:

2017-07 Standards Alignment with Registration | Revised Standards Authorization Request

Comment Period Start Date:

2/1/2018

Comment Period End Date:

3/2/2018

Associated Ballots:

There were 18 sets of responses, including comments from approximately 67 different people from approximately 53 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. The SAR drafting team added “Additionally, the project will consider whether to include a definition for UFLS into the NERC Glossary of
Terms, as well as review the standards to ensure consistent use of the term Planning Coordinator.” Do you agree the project should consider
including a definition for UFLS into the NERC Glossary of Terms and reviewing the standards to ensure consistent use of the term Planning
Coordinator? If not, please explain why you do not agree and, if possible, provide specific language revisions that would make it acceptable
to you.

2. Project 2017-07 is a review and alignment effort resulting from the RBR Initiative project and would modify Reliability Standards to be
consistent with the FERC-approved changes; as such, the SAR Drafting Team has removed references to PRC-004 and PRC-008 as being out
of scope for this project. Do you agree that references to PRC-004 and PRC-008 should be removed from the SAR? If not, please explain why
you do not agree and, if possible, provide specific language revisions that would make it acceptable to you.

3. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:

Organization
Name
Brian Van
Gheem

Southwest
Power Pool,
Inc. (RTO)

Name

Brian Van
Gheem

Charles
Yeung

Segment(s)

6

2

Region

NA - Not
Applicable

SPP RE

Group Name

Group Member
Name

ACES
Bob Solomon
Standards
Collaborators

SRC

Group
Member
Organization
Hoosier
Energy Rural
Electric
Cooperative,
Inc.

Group
Member
Segment(s)
1

Group Member
Region
RF

Ginger Mercier

Prairie Power, 1,3
Inc.

SERC

Kevin Lyons

Central Iowa
Power
Cooperative

1

MRO

Lucia Beal

Southern
Maryland
Electric
Cooperative

3

RF

Scott Brame

North Carolina 3,4,5
Electric
Membership
Corporation

SERC

Bill Hutchison

Southern
Illinois Power
Cooperative

1

SERC

Ryan Strom

Buckeye
Power, Inc.

4

RF

Shari Heino

Brazos
1,5
Electric Power
Cooperative,
Inc.

Texas RE

Amber Skillern

East Kentucky 1,3
Power
Cooperative

SERC

Susan Sosbe

Wabash
Valley Power
Association

3

RF

Ben Li

IESO

2

NPCC

Greg Campoli

NYISO

2

NPCC

Lori Spence

MISO

2

MRO

Mark Holman

PJM

2

RF

Matt Goldberg

ISONE

1

NPCC

Ali Miremadi

CAISO

1

WECC

Duke Energy

Exelon

Northeast
Power
Coordinating
Council

Colby Bellville 1,3,5,6

FRCC,RF,SERC Duke Energy

Daniel Gacek 1,3,5,6

Ruida Shu

1,2,3,4,5,6,7,8,9,10 NPCC

Exelon
Utilities

RSC no ISONE

Nathan Bigbee

ERCOT

1

Texas RE

Doug Hils

Duke Energy

1

RF

Dale Goodwine

Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

Chris Scanlon

BGE, ComEd, 1
PECO TO's

RF

John Bee

BGE, ComEd, 3
PECO LSE's

RF

Guy V. Zito

Northeast
Power
Coordinating
Council

10

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Wayne Sipperly

New York
Power
Authority

4

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian Robinson

Utility
Services

5

NPCC

Bruce Metruck

New York
Power
Authority

6

NPCC

Alan Adamson

New York
State
Reliability
Council

7

NPCC

Edward Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele Tondalo

UI

1

NPCC

Laura Mcleod

NB Power

1

NPCC

David
Ramkalawan

Ontario Power 5
Generation
Inc.

NPCC

Quintin Lee

Eversource
Energy

NPCC

1

Southwest
Power Pool,
Inc. (RTO)

Shannon
Mickens

2

MRO,SPP RE

Paul Malozewski Hydro One
3
Networks, Inc.

NPCC

Helen Lainis

IESO

2

NPCC

Michael
Schiavone

National Grid

1

NPCC

Michael Jones

National Grid

3

NPCC

Greg Campoli

NYISO

2

NPCC

Silvia Mitchell

NextEra
6
Energy Florida Power
and Light Co.

NPCC

Michael Forte

Con Ed Consolidated
Edison

1

NPCC

Daniel Grinkevich Con Ed 1
Consolidated
Edison Co. of
New York

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Brian O'Boyle

Con Ed Consolidated
Edison

5

NPCC

Sean Cavote

PSEG

4

NPCC

Sean Bodkin

Dominion Dominion
Resources,
Inc.

6

NPCC

Sylvain Clermont Hydro Quebec 1

NPCC

Chantal Mazza

Hydro Quebec 2

NPCC

AES - AES
Corporation

NA - Not
Applicable

SPP
Leo Bernier
Standards
Review Group

5

1. The SAR drafting team added “Additionally, the project will consider whether to include a definition for UFLS into the NERC Glossary of
Terms, as well as review the standards to ensure consistent use of the term Planning Coordinator.” Do you agree the project should consider
including a definition for UFLS into the NERC Glossary of Terms and reviewing the standards to ensure consistent use of the term Planning
Coordinator? If not, please explain why you do not agree and, if possible, provide specific language revisions that would make it acceptable
to you.
Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
1.

Utility Services agrees that a definition for UFLS and/or UFLS Program should be considered to be included in the NERC Glossary of Terms.

2. The FERC Order approving the Risk Based Registration Initiative did not include provisions for examining the consistent use of the term
Planning Coordinator. We suggest this effort should be addressed as part of the Standards Efficiency Review project.
Likes

0

Dislikes

0

Response

Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC
Answer

No

Document Name
Comment
The IRC SRC supports adding a definition for UFLS into the Glossary of Terms. We do not agree that the review of all NERC standards for consistent
use of the term Planning Coordinator is fruitful until the Standards Effiency Review (SER) process is complete. This process may result in siginificant
reductions and/or modifications to the NERC reliability standards. In fact, it would be more efficient to assess the consistency of “Planning Coordinator”
if and when SARs are issued from the SER process. Unless there is a known problem with compliance and/or with ensuring reliabitliy of the grid due to
the lack of consistent application of the term, we see no need to undertake such a review at this time.

Likes

0

Dislikes

0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment
UFLS should be well defined to reduce the confusion and subjectivity of assureing perfomance. There is a lot of inconsistency in how UFLS is currently
being identified. This has resulted in a lot of subjectivity in auditing against these standards.
Likes

0

Dislikes

0

Response

Daniel Gacek - Exelon - 1,3,5,6, Group Name Exelon Utilities
Answer

Yes

Document Name
Comment
The Exelon companies request that the SAR team provide additional detail regarding the changes to the SAR. We did not see anything in previous
revisions or comments about the Planning Coordinator role.
Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 3,5
Answer

Yes

Document Name
Comment

AEP has no objections to the standard drafting team considering adding a definition for UFLS to the NERC Glossary of Terms.

Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
The SPP Standards Review Group is in support of the SAR drafting team considering the inclusion of a definition for UFLS into the NERC Glossary of
Terms. However, we would also ask the drafting team to take into consideration adding both the manual and automatic load shedding processes into
their preliminary discussions for the development of the UFLS definition. From our perspective, the two processes need to be considered in order to
maintain integrity and flexibility to the UFLS process as well as help the industry meet their functional roles pertaining to the reliability of the BES. As we
reviewed standards like PRC-006-3, we observed that the term “UFLS Program” is mentioned throughout the document, however, it’s not defined in the
NERC Glossary of Terms. Additionally, we reviewed the UVLS Program definition and our interpretation would have us believe that this definition is only
addressing the automatic load shedding process. Finally, our research helped us identify that there is no definition in the NERC Glossary of Terms
pertaining to manual load shedding. At this point of the process, we would like to suggest two options that could be used in your discussion in reference
to the UFLS definition (see below).
Option 1
We suggest developing definitions for both terms “manual load shedding” and “UFLS Program” as well as including them in the NERC Glossary of
Terms. This option may require developing a definition for manual load shedding as well UFLS Program.
Option 2
We suggest developing a definition for “UFLS Program” as you could use the “UVLS Program” definition as a foundational anchor and modify the
definition to incorporate “manual load shedding” (see example below). However, this proposed action may require coordination with the UVLS drafting
team (which may be out of scope) and may require the revision of the UVLS Program definition in the future.
Undervoltage Load Shedding Program (original definition) - An automatic load shedding program, consisting of distributed relays and controls, used
to mitigate undervoltage conditions impacting the Bulk Electric System (BES), leading to voltage instability, voltage collapse, or Cascading. Centrally
controlled undervoltage-based load shedding is not included.
Underfrequency Load Shedding Program (modified proposed definition) - Manual and automatic load shedding programs, consisting of
distributed relays and controls, used to mitigate underfrequency conditions impacting the Bulk Electric System (BES), leading to voltage instability,
voltage collapse, or Cascading. Centrally controlled undervoltage-based load shedding aer not included.

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1,3,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Michelle Amarantos - APS - Arizona Public Service Co. - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Hien Ho - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - David Ramkalawan - 5
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no ISO-NE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Brian Van Gheem - Brian Van Gheem - 6, Group Name ACES Standards Collaborators
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Vine - Richard Vine - 2
Answer
Document Name
Comment
The California ISO supports the comments of the ISO/RTO Council Standards Review Committee
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Document Name
Comment
Texas RE is not opposed to defining UFLS, as long as it focuses on the technical side of UFLS and does not attempt to narrow the scope of
applicability.
Likes

0

Dislikes
Response

0

2. Project 2017-07 is a review and alignment effort resulting from the RBR Initiative project and would modify Reliability Standards to be
consistent with the FERC-approved changes; as such, the SAR Drafting Team has removed references to PRC-004 and PRC-008 as being out
of scope for this project. Do you agree that references to PRC-004 and PRC-008 should be removed from the SAR? If not, please explain why
you do not agree and, if possible, provide specific language revisions that would make it acceptable to you.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
Reliability Standard PRC-008 is not scheduled to be retired until 2027, as part of the PRC-005-6 implementation plan. Texas RE recommends including
PRC-008 until it is fully retired.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 3,5
Answer

Yes

Document Name
Comment

AEP has no objections to removing PRC-004 and PRC-008 from the proposed SAR for Project 2017-07.

Likes

0

Dislikes

0

Response

Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
1. Utility Services agrees that references to PRC-004 ad PRC-008 are out of scope for this project, and, it should be noted that these two
Standards were never part of the original FERC Order approving the Risk Based Registration Initiative.
Likes

0

Dislikes

0

Response

Brian Van Gheem - Brian Van Gheem - 6, Group Name ACES Standards Collaborators
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no ISO-NE
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

David Ramkalawan - David Ramkalawan - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Hien Ho - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Michelle Amarantos - APS - Arizona Public Service Co. - 1,3,5,6
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Daniel Gacek - Exelon - 1,3,5,6, Group Name Exelon Utilities

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Vine - Richard Vine - 2
Answer
Document Name
Comment
The California ISO supports the comments of the ISO/RTO Council Standards Review Committee

Likes

0

Dislikes
Response

0

3. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:
Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer
Document Name
Comment
1. The redline edit of the phrase ‘the appropriate applicable entity’ in the Detailed Description section has been changed to ‘the appropriate
functional entity’ in this SAR posting, however this does not sufficiently clarify that the reassignment of applicability will only be to ‘the
appropriate NERC registered entity’ as suggested by commenters in the previous posting. This phrase should be clarified to indicate only
NERC registered entities will be potentially reassigned applicability.
Likes

0

Dislikes

0

Response

Richard Vine - Richard Vine - 2
Answer
Document Name
Comment
The California ISO supports the comments of the ISO/RTO Council Standards Review Committee
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
None
Likes
Dislikes

0
0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
As stated in the previous comment period to this SAR, Texas RE recommends the SAR drafting team consider adding UFLS-only DPs to the
applicability and requirement section of additional standards than were listed in the SAR. Texas RE does not agree that these standards are out of
scope for this project and there is a reliability risk associated with not including UFLS-only DPs to the applicability and requirements sections of the
standards described below. Texas RE notes the SAR does include reviewing the standards to ensure consistent use of the term Planning
Coordinator. Texas RE respectfully requests the SAR drafting team describe how these standards are not in scope of this project. Furthermore, why is
it in scope to review the standards to ensure consistent use of the term Planning Coordinator, but out of scope to review the standards listed below for
consideration of adding UFLS-only DPs? Texas RE suggests it would be more efficient to consider making these changes now, while there is an open
project related to applicability, rather than later, when there may or may not be an open project related to these standards.

Texas RE requests consideration of the following standards:
•

EOP-004 – Add UFLS-only DPs as an entity with Reporting Responsibility in Attachment 1 to the following Event Types:
o

Automatic firm load shedding ≥ 100 MW (via automatic undervoltage or underfrequency load shedding schemes, or RAS) – If the
event occurs to a UFLS-only DP, should be expected to have reporting responsibility. If it is not required, the UFLS-only DP may not
report the event and thus there would be no opportunity to analyze it and make improvements in the future.

o

Damage or destruction of a Facility - UFLS DPs should have reporting responsibilities since one of the last lines of reliability defense is
underfrequency relaying entities. If it is not required, the UFLS-only DP may not report the event and thus there would be no
opportunity to analyze it and make improvements in the future.

•

FAC-002 - FAC-002 needs to include UFLS-only DPs in the applicability section so new or materially-modified existing Facilities are coordinated
and studied appropriately. If FAC-002 does not include UFLS-only DPs, the UFLS-only DP may not coordinate and cooperate on studies with
its Transmission Planner or Planning Coordinator in accordance with FAC-002-2 Requirement R3.

•

IRO-010 – If the UFLS-only DPs are not included, they may not provide data to its Reliability Coordinator in accordance with Requirement
R3. This standard should include UFLS-only DP entities so that an RC can fully understand post-contingent projected system conditions (i.e.
OPA and RTA) that may recognize a possible underfrequency event and corresponding reaction to said event. If the RC does not have the
UFLS information available that analyses will be incomplete. The same issue applies to TOP-003.

•

COM-002 – If UFLS-only DP is not added to the applicability, that entity may not do the training required by COM-002-4 Requirement R3 or
three-part communication as required by COM-002-4 Requirement R6. A UFLS-only DP may receive Operating Instructions to coordinate the
re-energization of underfrequency relay equipped load. That would indicate the need for proper communications between the appropriate
parties. Furthermore, during a Blackstart scenario the UFLS-only DP may be required to not re-energize load (through an Operating Instruction)
to help coordinate the stabilization of the grid during restoration.

Texas RE suggests modifying the SAR language to include these additional standards: “Additionally, the project will include adding Underfrequency
Load Shedding (UFLS)-only DPs to the Applicability Section and to the applicable Requirement language of COM-002, EOP-004, FAC-002,
IRO-010, TOP-003, PRC-005, PRC-006 and other standards noted during this project. The project will also include reviewing and revising

adding UFLS-only DP as appropriate to the Applicability Sections and Requirement language for PRC-004 and PRC-008 and any other
Standard to which this issue may apply.”
Likes

0

Dislikes

0

Response

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
N/A
Likes

0

Dislikes

0

Response

Brian Van Gheem - Brian Van Gheem - 6, Group Name ACES Standards Collaborators
Answer
Document Name
Comment
1. We believe the SAR Type should include the option of withdrawing or retiring a Reliability Standard. If the SDT is assigned to implement the
recommendations from a periodic review process, these could include the retirement of specific standards.
2. Under the detailed description of the proposed SAR, references to the FAC, INT, MOD, and NUC standard families are missing from the list of
clean-up efforts to modify the Reliability Standard applicable entities (category #2). We ask the SDT to include these references under the
specific clean-up effort category.
3. We believe a clarification is necessary regarding the intentions to review Reliability Standards and ensure consistent use of Planning
Coordinator. A resolution to the long-standing debate between Planning Authority versus Planning Coordinator is long overdue, and we believe
a separate clean-up effort should be identified. We propose the inclusion of “Modifications to existing standards and NERC Glossary Terms
that replace references to Planning Authority with Planning Coordinator” to the list.
4. We thank you for this opportunity to provide these comments.
Likes

0

Dislikes
Response

0

Consideration of Comments
Project Name:

2017-07 Standards Alignment with Registration | Revised Standards Authorization Request

Comment Period Start
Date:

2/1/2018

Comment Period End Date: 3/2/2018
Associated Ballots:

There were 18 sets of responses, including comments from approximately 76 different people from approximately 62 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Senior Director of Standards and
Education, Howard Gugel (via email) or at (404) 446‐9693.

Questions
1. The SAR drafting team added “Additionally, the project will consider whether to include a definition for UFLS into the NERC Glossary of
Terms, as well as review the standards to ensure consistent use of the term Planning Coordinator.” Do you agree the project should
consider including a definition for UFLS into the NERC Glossary of Terms and reviewing the standards to ensure consistent use of the term
Planning Coordinator? If not, please explain why you do not agree and, if possible, provide specific language revisions that would make it
acceptable to you.
2. Project 2017-07 is a review and alignment effort resulting from the RBR Initiative project and would modify Reliability Standards to be
consistent with the FERC-approved changes; as such, the SAR Drafting Team has removed references to PRC-004 and PRC-008 as being out
of scope for this project. Do you agree that references to PRC-004 and PRC-008 should be removed from the SAR? If not, please explain
why you do not agree and, if possible, provide specific language revisions that would make it acceptable to you.
3. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

2

Organization
Name

Name

Segment(s)

ACES Power Brian Van 6
Marketing Gheem

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

Region

NA - Not
Applicable

Group Name

Group
Member
Name

ACES
Greg
Standards
Froehling
Collaborators

Group
Group
Group Member Region
Member
Member
Organization Segment(s)
Rayburn
3
Country
Electric
Cooperative,
Inc.

SPP RE

Bob Solomon Hoosier
1
Energy Rural
Electric
Cooperative,
Inc.

RF

Ginger
Mercier

Prairie
Power, Inc.

SERC

Kevin Lyons

Central Iowa 1
Power
Cooperative

MRO

Lucia Beal

Southern
3
Maryland
Electric
Cooperative

RF

Scott Brame

North
3,4,5
Carolina
Electric
Membership
Corporation

SERC

1,3

3

Southwest Charles
Power Pool, Yeung
Inc. (RTO)

2

SPP RE

SRC

Tara Lightner Sunflower 1
Electric
Power
Corporation

SPP RE

Bill Hutchison Southern
1
Illinois
Power
Cooperative

SERC

Ryan Strom

Buckeye
Power, Inc.

RF

Shari Heino

Brazos
1,5
Electric
Power
Cooperative,
Inc.

Texas RE

Amber
Skillern

East
1,3
Kentucky
Power
Cooperative

SERC

Susan Sosbe Wabash
3
Valley Power
Association

RF

Charles
Yeung

SPP

2

SPP RE

Ben Li

IESO

2

NPCC

Greg Campoli NYISO

2

NPCC

Lori Spence

2

MRO

2

RF

MISO

Mark Holman PJM
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

4

4

Matt
Goldberg

Exelon

Chris
Scanlon

Duke Energy Colby
Bellville

1,3,5,6

1,3,5,6

Exelon
Utilities

1

NPCC

Ali Miremadi CAISO

1

WECC

Nathan
Bigbee

1

Texas RE

ERCOT

Chris Scanlon BGE, ComEd, 1
PECO TO's

RF

John Bee

BGE, ComEd, 3
PECO LSE's

RF

FRCC,RF,SERC Duke Energy Doug Hils

Duke Energy 1

RF

Northeast
Ruida Shu 1,2,3,4,5,6,7,8,9,10 NPCC
Power
Coordinating
Council

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

ISONE

RSC no ISONE

Lee Schuster Duke Energy 3

FRCC

Dale
Goodwine

Duke Energy 5

SERC

Greg Cecil

Duke Energy 6

RF

Guy V. Zito

Northeast
10
Power
Coordinating
Council

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Wayne
Sipperly

New York
Power
Authority

4

NPCC

Glen Smith

Entergy
Services

4

NPCC

5

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

Brian
Robinson

Utility
Services

5

NPCC

Bruce
Metruck

New York
Power
Authority

6

NPCC

Alan
Adamson

New York
State
Reliability
Council

7

NPCC

Edward
Bedder

Orange &
Rockland
Utilities

1

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele
Tondalo

UI

1

NPCC

Laura Mcleod NB Power

1

NPCC

David
Ontario
Ramkalawan Power
Generation
Inc.

5

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

Paul
Malozewski

Hydro One
Networks,
Inc.

3

NPCC

Helen Lainis

IESO

2

NPCC
6

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

Michael
Schiavone

National
Grid

1

NPCC

Michael
Jones

National
Grid

3

NPCC

Greg Campoli NYISO

2

NPCC

Silvia Mitchell NextEra
Energy Florida
Power and
Light Co.

6

NPCC

Michael Forte Con Ed 1
Consolidated
Edison

NPCC

Daniel
Grinkevich

Con Ed 1
Consolidated
Edison Co. of
New York

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Brian O'Boyle Con Ed 5
Consolidated
Edison

NPCC

Sean Cavote PSEG

4

NPCC

Sean Bodkin Dominion Dominion

6

NPCC

7

Resources,
Inc.

Southwest Shannon
Power Pool, Mickens
Inc. (RTO)

2

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

SPP RE

SPP
Standards
Review
Group

Sylvain
Clermont

Hydro
Quebec

1

NPCC

Chantal
Mazza

Hydro
Quebec

2

NPCC

Shannon
Mickens

Southwest
Power Pool
Inc.

2

SPP RE

Don Schmit

Nebraska
5
Public Power
District

SPP RE

Deborah
McEndaffer

Midwest
Energy, Inc

Leo Bernier

AES - AES
5
Corporation

NA - Not
SPP RE
Applicable
NA - Not Applicable

Louis Guidry Cleco

1,3,5,6

SPP RE

Mike Kidwell Empire
District
Electric
Company

1,3,5

SPP RE

8

1. The SAR drafting team added “Additionally, the project will consider whether to include a definition for UFLS into the NERC Glossary of
Terms, as well as review the standards to ensure consistent use of the term Planning Coordinator.” Do you agree the project should
consider including a definition for UFLS into the NERC Glossary of Terms and reviewing the standards to ensure consistent use of the term
Planning Coordinator? If not, please explain why you do not agree and, if possible, provide specific language revisions that would make it
acceptable to you.
Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

No

Document Name
Comment
1.

Utility Services agrees that a definition for UFLS and/or UFLS Program should be considered to be included in the NERC Glossary of
Terms.

2. The FERC Order approving the Risk Based Registration Initiative did not include provisions for examining the consistent use of the term

Planning Coordinator. We suggest this effort should be addressed as part of the Standards Efficiency Review project.

Likes

0

Dislikes

0

Response
Thank you for your comments. The SAR drafting team agrees with your comment and has added “and/or UFLS Program” to the SAR for this
project. Project 2017-07 is a review and alignment effort resulting from the RBR Initiative project and would modify Reliability Standards to be
consistent with the FERC-approved changes. It is a NERC initiative to examine the standards for the consistent use of the term Planning
Coordinator. The SAR drafting team believes it is appropriate to address those issues at this time and as part of this development effort.
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC
Answer

No

Document Name
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

9

Comment
The IRC SRC supports adding a definition for UFLS into the Glossary of Terms. We do not agree that the review of all NERC standards for
consistent use of the term Planning Coordinator is fruitful until the Standards Effiency Review (SER) process is complete. This process may
result in siginificant reductions and/or modifications to the NERC reliability standards. In fact, it would be more efficient to assess the
consistency of “Planning Coordinator” if and when SARs are issued from the SER process. Unless there is a known problem with compliance
and/or with ensuring reliabitliy of the grid due to the lack of consistent application of the term, we see no need to undertake such a review at
this time.
Likes

0

Dislikes

0

Response
Thank you for your comments. It is a NERC initiative to examine the standards for the consistent use of the term Planning Coordinator. The
SAR drafting team believes it is appropriate to address those issues at this time and as part of this development effort.
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment
UFLS should be well defined to reduce the confusion and subjectivity of assureing perfomance. There is a lot of inconsistency in how UFLS is
currently being identified. This has resulted in a lot of subjectivity in auditing against these standards.
Likes

0

Dislikes

0

Response
Thank you for your affirmative comment.
Chris Scanlon - Exelon - 1,3,5,6, Group Name Exelon Utilities
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

10

Answer

Yes

Document Name
Comment
The Exelon companies request that the SAR team provide additional detail regarding the changes to the SAR. We did not see anything in
previous revisions or comments about the Planning Coordinator role.
Likes

0

Dislikes

0

Response
Thank you for your comments. Project 2017-07 is a review and alignment effort resulting from the RBR Initiative project and would modify
Reliability Standards to be consistent with the FERC-approved changes. It is a NERC initiative to examine the standards for the consistent use
of the term Planning Coordinator. The SAR drafting team believes it is appropriate to address those issues at this time and as part of this
development effort. The addition of the Planning Coordinator examination for consistent use in the standards was added to this version of
the SAR and the SAR was reposted due to the changes made to the SAR.
Thomas Foltz - AEP - 3,5
Answer

Yes

Document Name
Comment
AEP has no objections to the standard drafting team considering adding a definition for UFLS to the NERC Glossary of Terms.

Likes

0

Dislikes

0

Response
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

11

Thank you for your affirmative comment.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
The SPP Standards Review Group is in support of the SAR drafting team considering the inclusion of a definition for UFLS into the NERC
Glossary of Terms. However, we would also ask the drafting team to take into consideration adding both the manual and automatic load
shedding processes into their preliminary discussions for the development of the UFLS definition. From our perspective, the two processes
need to be considered in order to maintain integrity and flexibility to the UFLS process as well as help the industry meet their functional roles
pertaining to the reliability of the BES. As we reviewed standards like PRC-006-3, we observed that the term “UFLS Program” is mentioned
throughout the document, however, it’s not defined in the NERC Glossary of Terms. Additionally, we reviewed the UVLS Program definition
and our interpretation would have us believe that this definition is only addressing the automatic load shedding process. Finally, our research
helped us identify that there is no definition in the NERC Glossary of Terms pertaining to manual load shedding. At this point of the process,
we would like to suggest two options that could be used in your discussion in reference to the UFLS definition (see below).
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

12

Option 1
We suggest developing definitions for both terms “manual load shedding” and “UFLS Program” as well as including them in the NERC Glossary
of Terms. This option may require developing a definition for manual load shedding as well UFLS Program.
Option 2
We suggest developing a definition for “UFLS Program” as you could use the “UVLS Program” definition as a foundational anchor and modify
the definition to incorporate “manual load shedding” (see example below). However, this proposed action may require coordination with the
UVLS drafting team (which may be out of scope) and may require the revision of the UVLS Program definition in the future.
Undervoltage Load Shedding Program (original definition) - An automatic load shedding program, consisting of distributed relays and
controls, used to mitigate undervoltage conditions impacting the Bulk Electric System (BES), leading to voltage instability, voltage collapse, or
Cascading. Centrally controlled undervoltage-based load shedding is not included.
Underfrequency Load Shedding Program (modified proposed definition) - Manual and automatic load shedding programs, consisting of
distributed relays and controls, used to mitigate underfrequency conditions impacting the Bulk Electric System (BES), leading to voltage
instability, voltage collapse, or Cascading. Centrally controlled undervoltage-based load shedding aer not included.
Likes

0

Dislikes

0

Response
Thank you for your comments. The SAR drafting team has added to the SAR: “UFLS and/or UFLS Program” for definition consideration. UVLS
definitions would be out of scope for this project. The future standards drafting team will consider and develop what components UFLS
Program consists of, should the future drafting team develop a definition for UFLS Program.
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

13

Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Scott Langston - Tallahassee Electric (City of Tallahassee, FL) - 1,3,5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Michelle Amarantos - APS - Arizona Public Service Co. - 1,3,5,6
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

14

Answer

Yes

Document Name
Comment
Thank you for your affirmative response.
Likes

0

Dislikes

0

Response
Hien Ho - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Document Name
Comment
Thank you for your affirmative response.
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

15

Dislikes

0

Response
Thank you for your affirmative response.
David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no ISO-NE
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Brian Van Gheem - ACES Power Marketing - 6, Group Name ACES Standards Collaborators
Answer

Yes

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

16

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the ISO/RTO Council Standards Review Committee
Likes

0

Dislikes

0

Response
Thank you for your comment. Please see responses to ISO/RTO Council Standards Review Committee.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE is not opposed to defining UFLS, as long as it focuses on the technical side of UFLS and does not attempt to narrow the scope of
applicability.
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

17

Likes

0

Dislikes

0

Response
Thank you for your affirmative comment.

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

18

2. Project 2017-07 is a review and alignment effort resulting from the RBR Initiative project and would modify Reliability Standards to be
consistent with the FERC-approved changes; as such, the SAR Drafting Team has removed references to PRC-004 and PRC-008 as being out
of scope for this project. Do you agree that references to PRC-004 and PRC-008 should be removed from the SAR? If not, please explain
why you do not agree and, if possible, provide specific language revisions that would make it acceptable to you.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

No

Document Name
Comment
Reliability Standard PRC-008 is not scheduled to be retired until 2027, as part of the PRC-005-6 implementation plan. Texas RE recommends
including PRC-008 until it is fully retired.
Likes

0

Dislikes

0

Response
Thank you for your comment. The SAR drafting team removed PRC-008 from the SAR as being out of scope of the project. PRC-008 is not
contained within the FERC Order approving the Risk Based Registration Initiative.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

19

Response
Thank you for your affirmative response.
Thomas Foltz - AEP - 3,5
Answer

Yes

Document Name
Comment
AEP has no objections to removing PRC-004 and PRC-008 from the proposed SAR for Project 2017-07.
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer

Yes

Document Name
Comment
1. Utility Services agrees that references to PRC-004 ad PRC-008 are out of scope for this project, and, it should be noted that these two

Standards were never part of the original FERC Order approving the Risk Based Registration Initiative.

Likes

0

Dislikes

0

Response
Thank you for your affirmative comment.
Brian Van Gheem - ACES Power Marketing - 6, Group Name ACES Standards Collaborators
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

20

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no ISO-NE
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

21

Dislikes

0

Response
Thank you for your affirmative response.
David Ramkalawan - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Hien Ho - Tacoma Public Utilities (Tacoma, WA) - 1,3,4,5,6
Answer

Yes

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

22

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Michelle Amarantos - APS - Arizona Public Service Co. - 1,3,5,6
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Charles Yeung - Southwest Power Pool, Inc. (RTO) - 2, Group Name SRC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

23

Response
Thank you for your affirmative response.
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Chris Scanlon - Exelon - 1,3,5,6, Group Name Exelon Utilities
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

24

Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your affirmative response.
Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the ISO/RTO Council Standards Review Committee
Likes

0

Dislikes

0

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

25

Response
Thank you for your comment. Please see response to ISO/RTO Council Standards Review Committee.

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

26

3. If you have any other comments on this SAR that you haven’t already mentioned above, please provide them here:
Brian Evans-Mongeon - Utility Services, Inc. - 4
Answer
Document Name
Comment
1. The redline edit of the phrase ‘the appropriate applicable entity’ in the Detailed Description section has been changed to ‘the

appropriate functional entity’ in this SAR posting, however this does not sufficiently clarify that the reassignment of applicability will
only be to ‘the appropriate NERC registered entity’ as suggested by commenters in the previous posting. This phrase should be
clarified to indicate only NERC registered entities will be potentially reassigned applicability.

Likes

0

Dislikes

0

Response
Thank you for your comment. The SAR drafting team has updated the SAR to read: “appropriate registered functional entity.”
Richard Vine - California ISO - 2
Answer
Document Name
Comment
The California ISO supports the comments of the ISO/RTO Council Standards Review Committee
Likes

0

Dislikes

0

Response
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

27

Thank you for your comment. Please see response to ISO/RTO Council Standards Review Committee.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
None
Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
As stated in the previous comment period to this SAR, Texas RE recommends the SAR drafting team consider adding UFLS-only DPs to the
applicability and requirement section of additional standards than were listed in the SAR. Texas RE does not agree that these standards are
out of scope for this project and there is a reliability risk associated with not including UFLS-only DPs to the applicability and requirements
sections of the standards described below. Texas RE notes the SAR does include reviewing the standards to ensure consistent use of the term
Planning Coordinator. Texas RE respectfully requests the SAR drafting team describe how these standards are not in scope of this
project. Furthermore, why is it in scope to review the standards to ensure consistent use of the term Planning Coordinator, but out of scope
to review the standards listed below for consideration of adding UFLS-only DPs? Texas RE suggests it would be more efficient to consider
making these changes now, while there is an open project related to applicability, rather than later, when there may or may not be an open
project related to these standards.
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

28

Texas RE requests consideration of the following standards:
•

EOP-004 – Add UFLS-only DPs as an entity with Reporting Responsibility in Attachment 1 to the following Event Types:
o

o

Automatic firm load shedding ≥ 100 MW (via automatic undervoltage or underfrequency load shedding schemes, or RAS) –
If the event occurs to a UFLS-only DP, should be expected to have reporting responsibility. If it is not required, the UFLS-only
DP may not report the event and thus there would be no opportunity to analyze it and make improvements in the future.
Damage or destruction of a Facility - UFLS DPs should have reporting responsibilities since one of the last lines of reliability
defense is underfrequency relaying entities. If it is not required, the UFLS-only DP may not report the event and thus there
would be no opportunity to analyze it and make improvements in the future.

•

FAC-002 - FAC-002 needs to include UFLS-only DPs in the applicability section so new or materially-modified existing Facilities are
coordinated and studied appropriately. If FAC-002 does not include UFLS-only DPs, the UFLS-only DP may not coordinate and
cooperate on studies with its Transmission Planner or Planning Coordinator in accordance with FAC-002-2 Requirement R3.

•

IRO-010 – If the UFLS-only DPs are not included, they may not provide data to its Reliability Coordinator in accordance with
Requirement R3. This standard should include UFLS-only DP entities so that an RC can fully understand post-contingent projected
system conditions (i.e. OPA and RTA) that may recognize a possible underfrequency event and corresponding reaction to said event. If
the RC does not have the UFLS information available that analyses will be incomplete. The same issue applies to TOP-003.

•

COM-002 – If UFLS-only DP is not added to the applicability, that entity may not do the training required by COM-002-4 Requirement
R3 or three-part communication as required by COM-002-4 Requirement R6. A UFLS-only DP may receive Operating Instructions to
coordinate the re-energization of underfrequency relay equipped load. That would indicate the need for proper communications
between the appropriate parties. Furthermore, during a Blackstart scenario the UFLS-only DP may be required to not re-energize load
(through an Operating Instruction) to help coordinate the stabilization of the grid during restoration.

Texas RE suggests modifying the SAR language to include these additional standards: “Additionally, the project will include adding
Underfrequency Load Shedding (UFLS)-only DPs to the Applicability Section and to the applicable Requirement language of COM-002,
EOP-004, FAC-002, IRO-010, TOP-003, PRC-005, PRC-006 and other standards noted during this project. The project will also include
reviewing and revising adding UFLS-only DP as appropriate to the Applicability Sections and Requirement language for PRC-004 and
PRC-008 and any other Standard to which this issue may apply.”
Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

29

Likes

0

Dislikes

0

Response
Thank you for your comments. Project 2017-07 is a review and alignment effort resulting from the RBR Initiative project and would modify
Reliability Standards to be consistent with the FERC-approved changes. It is a NERC initiative to examine the standards for the consistent use
of the term Planning Coordinator. The SAR drafting team believes it is appropriate to address those issues at this time and as part of this
development effort.
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP RE, Group Name SPP Standards Review Group
Answer
Document Name
Comment
N/A
Likes

0

Dislikes

0

Response
Brian Van Gheem - ACES Power Marketing - 6, Group Name ACES Standards Collaborators
Answer
Document Name
Comment
1. We believe the SAR Type should include the option of withdrawing or retiring a Reliability Standard. If the SDT is assigned to

implement the recommendations from a periodic review process, these could include the retirement of specific standards.

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

30

2. Under the detailed description of the proposed SAR, references to the FAC, INT, MOD, and NUC standard families are missing from the

list of clean-up efforts to modify the Reliability Standard applicable entities (category #2). We ask the SDT to include these references
under the specific clean-up effort category.
3. We believe a clarification is necessary regarding the intentions to review Reliability Standards and ensure consistent use of Planning
Coordinator. A resolution to the long-standing debate between Planning Authority versus Planning Coordinator is long overdue, and
we believe a separate clean-up effort should be identified. We propose the inclusion of “Modifications to existing standards and NERC
Glossary Terms that replace references to Planning Authority with Planning Coordinator” to the list.
4. We thank you for this opportunity to provide these comments.
Likes

0

Dislikes

0

Response
Thank you for your comment. If requirement or standard retirement recommendations result from a periodic review, a SAR would be created
by the periodic review team(s). The future drafting team will be coordinating efforts with the periodic review teams. The SAR drafting team
has added FAC, INT, MOD, and NUC to Category No. 2. The SAR drafting team has updated the SAR to read: “as well as to conduct a review
and develop modifications to the standards to ensure consistent use of the term Planning Coordinator.”

Consideration of Comments
Project 2017-07 Alignment with Registration | May 2018

31

Unofficial Nomination Form

Project 2017-07 Standards Alignment with Registration
Standards Drafting Team
Do not use this form for submitting nominations. Use the electronic form to submit nominations by
8 p.m. Eastern, Monday, May 14, 2018. This unofficial version is provided to assist nominees in compiling
the information necessary to submit the electronic form.
Additional information about this project is available on the Project 2017-07 Standards Alignment with
Registration page. If you have questions, contact Standards Developer, Laura Anderson (via email), or at
404-446-9671.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
Previous drafting or review team experience is beneficial, but not required. A brief description of the
desired qualifications, expected commitment, and other pertinent information is included below.
Project 2017-07 Standards Alignment with Registration

The purpose of this project is focused on making the tailored Reliability Standards updates necessary to
reflect the retirement of PSEs, IAs, and LSEs (as well as all of their applicable references). This alignment
includes three categories:
1. Modifications to existing standards where the removal of the retired function may need
replacement by another function. For instance, Reliability Standard MOD-032-1 specifies certain
data from LSEs that may need to be provided by other functional entities going forward.
2. Modifications where the applicable entity and references may be removed. These updates may be
able to follow a similar process to the Paragraph 81 initiatives where standards are redlined and
posted for industry comment and ballot. A majority of the edits would simply remove
deregistered functional entities and their applicable requirements/references. The impacted
standards include the BAL, CIP, IRO, and TOP family of standards. Additionally, PRC-005 and PRC006 will be updated to add UFLS-only DP to the Applicability Sections.
3. Initiatives that can address RBR updates through the periodic review process. This would include
the INT-004-3.1 and NUC-001-3 standards. Rather than the Project 2017-07 making the revisions
the SDT could coordinate with the periodic review teams currently reviewing INT-004-3.1 and
NUC-001-3 so that any changes resulting from those periodic reviews, if any, may be proposed at
the same time after completion of each periodic review.
Standards affected:
This project will formally address any remaining edits to the Reliability Standards that are needed to align
the existing standards with the RBR initiatives. The edits include updates to the BAL, CIP, FAC, INT, IRO,

MOD, NUC, and TOP family of standards to remove the references to Purchasing-Selling Entities (PSEs)
and Interchange Authorities (IAs); references to the Load-Serving Entity (LSEs) will be removed or replaced
by the appropriate NERC Registered Entity. The project will include adding Underfrequency Load Shedding
(UFLS)-only DPs to the Applicability Section of PRC-005 and PRC-006 per NERC registration criteria.
Additionally, the project will consider whether to include a definition for UFLS into the NERC Glossary of
Terms, as well as reviewing the standards to ensure consistent use of the term Planning Coordinator.
On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North American
Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) Initiative in Docket No. RR15-4-000.
FERC approved the removal of two functional categories, Purchasing-Selling Entity (PSE) and Interchange
Authority (IA), from the NERC Compliance Registry due to the commercial nature of these categories
posing little or no risk to the reliability of the bulk power system.
FERC also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently approved on
compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria. Several
projects have addressed standards impacted by the RBR initiative since FERC approval; however, there
remain some Reliability Standards that require minor revisions so that they align with the post-RBR
registration impacts.
The time commitment for this project is expected to be up to two face-to-face meetings per quarter
(on average two full working days each meeting) with conference calls scheduled as needed to meet
the agreed-upon timeline the standards drafting team sets forth. Team members may also have side
projects, either individually or by subgroup, to present to the larger team for discussion and review.
Lastly, an important component of the standards drafting team effort is outreach. Members of the
team will be expected to conduct industry outreach during the development process to support a
successful project outcome.

Unofficial Nomination Form
Project 2017-07 Standards Alignment with Registration | May 2018

2

Name:
Organization:
Address:
Telephone:
E-mail:
Please briefly describe your experience and qualifications to serve on the requested Standard
Drafting Team (Bio):

If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
Texas RE
FRCC
MRO

NPCC
RF
SERC

SPP RE
WECC
NA – Not Applicable

Unofficial Nomination Form
Project 2017-07 Standards Alignment with Registration | May 2018

3

Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Select each Function 1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator

1

Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner

These functions are defined in the NERC Functional Model, which is available on the NERC web site.

Unofficial Nomination Form
Project 2017-07 Standards Alignment with Registration | May 2018

4

Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:
Name:

Telephone:

Organization:

E-mail:

Name:

Telephone:

Organization:

E-mail:

Provide the name and contact information of your immediate supervisor or a member of your
management who can confirm your organization’s willingness to support your active participation.
Name:

Telephone:

Title:

Email:

Unofficial Nomination Form
Project 2017-07 Standards Alignment with Registration | May 2018

5

Standards Announcement

Project 2017-07 Standards Alignment with Registration

Nomination Period Open through May 14, 2018
Now Available

Nominations are being sought for drafting team members for Project 2017-07 Standards Alignment
with Registration through 8 p.m. Eastern, Monday, May 14, 2018.
Use the electronic form to submit a nomination. If you experience any difficulties in using the
electronic form, contact Nasheema Santos. An unofficial Word version of the nomination form is
posted on the Drafting Team Vacancies page and the project page.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
The time commitment for this project is expected to be two face-to-face meetings per quarter (on
average two full working days each meeting) with conference calls scheduled as needed to meet the
agreed upon timeline the team sets forth. Team members may also have side projects, either
individually or by sub-group, to present for discussion and review. Lastly, an important component
of the team effort is outreach. Members of the team will be expected to conduct industry outreach
during the development process to support a successful ballot.
Previous team experience is beneficial but not required. See the project page and nomination form
for additional information.
Next Steps

The Standards Committee is expected to appoint members to the team in June 2018. Nominees will
be notified shortly after they have been appointed.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Laura Anderson (via email) or at
(404) 446- 9671.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower

Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Solicitation of Standard Drafting Team Nominations
Project 2017-07 Standards Alignment with Registration | August 2017

2

FAC-002-3 — Facility Interconnection Studies

A. Introduction
1.

Title:

Facility Interconnection Studies

2.

Number:

FAC-002-3

3.

Purpose: To study the impact of interconnecting new or materially modified
Facilities on the Bulk Electric System.

4.

Applicability:
4.1. Functional Entities:
4.1.1 Planning Coordinator
4.1.2 Transmission Planner
4.1.3 Transmission Owner
4.1.4 Distribution Provider
4.1.5 Generator Owner
4.1.6 Applicable Generator Owner
4.1.6.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.

B. Requirements and Measures
R1.

Each Transmission Planner and each Planning Coordinator shall study the reliability
impact of: (i) interconnecting new generation, transmission, or electricity end-user
Facilities and (ii) materially modifying existing interconnections of generation,
transmission, or electricity end-user Facilities. The following shall be studied:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
1.1. The reliability impact of the new interconnection, or materially modified existing
interconnection, on affected system(s);
1.2. Adherence to applicable NERC Reliability Standards; regional and Transmission
Owner planning criteria; and Facility interconnection requirements;
1.3. Steady-state, short-circuit, and dynamics studies, as necessary, to evaluate
system performance under both normal and contingency conditions; and
1.4. Study assumptions, system performance, alternatives considered, and
coordinated recommendations. While these studies may be performed
independently, the results shall be evaluated and coordinated by the entities
involved.

Draft 1 of FAC-002-3
October 2019

Page 1 of 9

FAC-002-3 — Facility Interconnection Studies

M1. Each Transmission Planner or each Planning Coordinator shall have evidence (such as
study reports, including documentation of reliability issues) that it met all
requirements in Requirement R1.
R2.

Each Generator Owner seeking to interconnect new generation Facilities, or to
materially modify existing interconnections of generation Facilities, shall coordinate
and cooperate on studies with its Transmission Planner or Planning Coordinator,
including but not limited to the provision of data as described in R1, Parts 1.1-1.4.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M2. Each Generator Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R2.
R3.

Each Transmission Owner and each Distribution Provider seeking to interconnect new
transmission Facilities or electricity end-user Facilities, or to materially modify existing
interconnections of transmission Facilities or electricity end-user Facilities, shall
coordinate and cooperate on studies with its Transmission Planner or Planning
Coordinator, including but not limited to the provision of data as described in R1,
Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M3. Each Transmission Owner and each Distribution Provider shall have evidence (such as
documents containing the data provided in response to the requests of the
Transmission Planner or Planning Coordinator) that it met all requirements in
Requirement R3.
R4.

Each Transmission Owner shall coordinate and cooperate with its Transmission
Planner or Planning Coordinator on studies regarding requested new or materially
modified interconnections to its Facilities, including but not limited to the provision of
data as described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

M4. Each Transmission Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R4.
R5.

Each applicable Generator Owner shall coordinate and cooperate with its
Transmission Planner or Planning Coordinator on studies regarding requested
interconnections to its Facilities, including but not limited to the provision of data as
described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon: Longterm Planning]

M5. Each applicable Generator Owner shall have evidence (such as documents containing
the data provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R5.

Draft 1 of FAC-002-3
October 2019

Page 2 of 9

FAC-002-3 — Facility Interconnection Studies

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the CEA may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Planning Coordinator, Transmission Planner, Transmission Owner,
Distribution Provider, Generator Owner and applicable Generator Owner shall
keep data or evidence to show compliance as identified below unless directed by
its CEA to retain specific evidence for a longer period of time as part of an
investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Draft 1 of FAC-002-3
October 2019

Page 3 of 9

FAC-002-3 — Facility Interconnection Studies

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

R1

Long-term
Planning

Medium The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities, but failed to
study one of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study two of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study three of the
Parts (R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator failed to
study the reliability
impact of:
interconnecting new
generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of,
generation,
transmission, or
electricity end-user
Facilities.

R2

Long-term
Planning

Medium The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

Draft 1 of FAC-002-3
October 2019

Page 4 of 9

FAC-002-3 — Facility Interconnection Studies

R#

R3

Time
Horizon

Long-term
Planning

Draft 1 of FAC-002-3
October 2019

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but
failed to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but
failed to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

failed to coordinate
and cooperate on
studies with its
Transmission Planner
or Planning
Coordinator.

Medium The Transmission
Owner or Distribution
Provider seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but

The Transmission
Owner, or Distribution
Provider Entity
seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning

The Transmission
Owner or Distribution
Provider Entity
seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning

The Transmission
Owner, or Distribution
Provider Entity
seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, failed to
coordinate and
cooperate on studies
with its Transmission

Page 5 of 9

FAC-002-3 — Facility Interconnection Studies

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

failed to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

Coordinator, but
failed to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

Coordinator, but failed Planner or Planning
to provide data
Coordinator.
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

R4

Long-term
Planning

Medium The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

The Transmission
Owner failed to
coordinate and
cooperate on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities.

R5

Long-term
Planning

Medium The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission

The applicable
Generator Owner
failed to coordinate
and cooperate on
studies with its

Draft 1 of FAC-002-3
October 2019

Page 6 of 9

FAC-002-3 — Facility Interconnection Studies

R#

Time
Horizon

Draft 1 of FAC-002-3
October 2019

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

Transmission Planner
or Planning
Coordinator regarding
requested
interconnections to its
Facilities.

Page 7 of 9

FAC-002-3 — Facility Interconnection Studies

D. Regional Variances
None.

E. Interpretations
None.

F. Associated Documents
None

Draft 1 of FAC-002-3
October
2019

Page 8 of 9

Application Guidelines

Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether
an existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.

Version History
Version

Date

Action

Change
Tracking

0

April 1, 2005

Effective Date

New

0

January 13, 2006

Removed duplication of “Regional
Reliability Organizations(s).

Errata

1

August 5, 2010

Modified to address Order No. 693
Directives contained in paragraph
693.
Adopted by the NERC Board of
Trustees.

Revised

1

February 7, 2013

R2 and associated elements
approved by NERC Board of Trustees
for retirement as part of the
Paragraph 81 project (Project 201302) pending applicable regulatory
approval.

1

November 21, 2013 R2 and associated elements
approved by FERC for retirement as
part of the Paragraph 81 project
(Project 2013-02)

2

Revisions to implement the
recommendations of the FAC FiveYear Review Team.

2

August 14, 2014

Adopted by the Board of Trustees.

2

November 6, 2014

FERC letter order issued approving
FAC-002-2.

2

Draft 1 of FAC-002-3
October 2019

Revision under
Project 2010-02

Adopted by the Board of Trustees.

Page 9 of 9

FAC-002-2 3 — Facility Interconnection Studies

A. Introduction
1.

Title:

Facility Interconnection Studies

2.

Number:

FAC-002-32

3.

Purpose: To study the impact of interconnecting new or materially modified
Facilities on the Bulk Electric System.

4.

Applicability:
4.1. Functional Entities:
4.1.1

Planning Coordinator

4.1.2

Transmission Planner

4.1.3

Transmission Owner

4.1.4

Distribution Provider

4.1.5

Generator Owner

4.1.6

Applicable Generator Owner

4.1.6.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
4.1.7 Load-Serving Entity
5.

Effective Date: The first day of the first calendar quarter that is one year after the
date that this 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 that is one year after the date this standard is adopted
by the NERC Board of Trustees or as otherwise provided for in that jurisdiction.

B. Requirements and Measures
R1. Each Transmission Planner and each Planning Coordinator shall study the reliability
impact of: (i) interconnecting new generation, transmission, or electricity end-user
Facilities and (ii) materially modifying existing interconnections of generation,
transmission, or electricity end-user Facilities. The following shall be studied:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
1.1. The reliability impact of the new interconnection, or materially modified existing
interconnection, on affected system(s);
1.2. Adherence to applicable NERC Reliability Standards; regional and Transmission
Owner planning criteria; and Facility interconnection requirements;
1.3. Steady-state, short-circuit, and dynamics studies, as necessary, to evaluate system
performance under both normal and contingency conditions; and

Page 1 of 8

FAC-002-2 3 — Facility Interconnection Studies

1.4. Study assumptions, system performance, alternatives considered, and coordinated
recommendations. While these studies may be performed independently, the
results shall be evaluated and coordinated by the entities involved.
M1. Each Transmission Planner or each Planning Coordinator shall have evidence (such as
study reports, including documentation of reliability issues) that it met all requirements
in Requirement R1.
R2. Each Generator Owner seeking to interconnect new generation Facilities, or to
materially modify existing interconnections of generation Facilities, shall coordinate
and cooperate on studies with its Transmission Planner or Planning Coordinator,
including but not limited to the provision of data as described in R1, Parts 1.1-1.4.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M2. Each Generator Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R2.
R3. Each Transmission Owner, and each Distribution Provider, and each Load-Serving
Entity seeking to interconnect new transmission Facilities or electricity end-user
Facilities, or to materially modify existing interconnections of transmission Facilities
or electricity end-user Facilities, shall coordinate and cooperate on studies with its
Transmission Planner or Planning Coordinator, including but not limited to the
provision of data as described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
M3. Each Transmission Owner, and each Distribution Provider, and each Load-Serving
Entity shall have evidence (such as documents containing the data provided in response
to the requests of the Transmission Planner or Planning Coordinator) that it met all
requirements in Requirement R3.
R4. Each Transmission Owner shall coordinate and cooperate with its Transmission
Planner or Planning Coordinator on studies regarding requested new or materially
modified interconnections to its Facilities, including but not limited to the provision of
data as described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
M4. Each Transmission Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R4.
R5. Each applicable Generator Owner shall coordinate and cooperate with its Transmission
Planner or Planning Coordinator on studies regarding requested interconnections to its
Facilities, including but not limited to the provision of data as described in R1, Parts
1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M5. Each applicable Generator Owner shall have evidence (such as documents containing
the data provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R5.

Page 2 of 8

FAC-002-2 3 — Facility Interconnection Studies

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The Planning Coordinator, Transmission Planner, Transmission Owner,
Distribution Provider, Generator Owner, and applicable Generator Owner, and
Load-Serving Entity shall keep data or evidence to show compliance as identified
below unless directed by its CEA to retain specific evidence for a longer period of
time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Page 3 of 8

FAC-002-2 3 — Facility Interconnection Studies

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

R1

Long-term
Planning

Medium The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities, but failed to
study one of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study two of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study three of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator failed to
study the reliability
impact of:
interconnecting new
generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of,
generation,
transmission, or
electricity end-user
Facilities.

R2

Long-term
Planning

Medium The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,
coordinated and
cooperated on studies

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,
coordinated and
cooperated on studies

The Generator Owner
seeking to interconnect
new generation
Facilities, or to
materially modify
existing
interconnections of
generation Facilities,
coordinated and
cooperated on studies

The Generator Owner
seeking to interconnect
new generation
Facilities, or to
materially modify
existing
interconnections of
generation Facilities,
failed to coordinate
and cooperate on

Page 4 of 8

FAC-002-2 3 — Facility Interconnection Studies

R3

Long-term
Planning

with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

studies with its
Transmission Planner
or Planning
Coordinator.

Medium The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, failed to
coordinate and
cooperate on studies
with its Transmission
Planner or Planning
Coordinator.

Page 5 of 8

FAC-002-2 3 — Facility Interconnection Studies

R4

Long-term
Planning

Medium The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in one of the
Parts (R1, 1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in two of the
Parts (R1, 1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in three of
the Parts (R1, 1.1-1.4).

The Transmission
Owner failed to
coordinate and
cooperate on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities.

R5

Long-term
Planning

Medium The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in one of the
Parts (R1, 1.1-1.4).

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in two of the
Parts (R1, 1.1-1.4).

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in three of
the Parts (R1, 1.1-1.4).

The applicable
Generator Owner
failed to coordinate
and cooperate on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested
interconnections to its
Facilities.

Page 6 of 8

FAC-002-2 3 — Facility Interconnection Studies

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None

Page 7 of 8

Application Guidelines
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.

Version History

Version

Date

Action

Change
Tracking

0

April 1, 2005

Effective Date

New

0

January 13, 2006

Removed duplication of “Regional
Reliability Organizations(s).

Errata

1

August 5, 2010

Modified to address Order No. 693
Directives contained in paragraph
693.
Adopted by the NERC Board of
Trustees.

Revised

1

February 7, 2013

1

November 21, 2013

R2 and associated elements approved
by NERC Board of Trustees for
retirement as part of the Paragraph 81
project (Project 2013-02) pending
applicable regulatory approval.
R2 and associated elements approved
by FERC for retirement as part of the
Paragraph 81 project (Project 201302)

2

Revisions to implement the
recommendations of the FAC FiveYear Review Team.

2

August 14, 2014

Adopted by the Board of Trustees.

2

November 6, 2014

FERC letter order issued approving
FAC-002-2.

2

Revision under
Project 2010-02

Adopted by the Board of Trustees.

Page 8 of 8

IRO-010-3 — Reliability Coordinator Data Specification and Collection

A. Introduction
1. Title:

Reliability Coordinator Data Specification and Collection

2. Number: IRO-010-3
3. Purpose: To prevent instability, uncontrolled separation, or Cascading outages that
adversely impact reliability, by ensuring the Reliability Coordinator has the data it needs
to monitor and assess the operation of its Reliability Coordinator Area.
4. Applicability
4.1. Reliability Coordinator.
4.2. Balancing Authority.
4.3. Generator Owner.
4.4. Generator Operator.
4.5. Transmission Operator.
4.6. Transmission Owner.
4.7. Distribution Provider.
5. Proposed Effective Date:
See Implementation Plan.
B. Requirements
R1.

The Reliability Coordinator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include but not be limited to:
(Violation Risk Factor: Low) (Time Horizon: Operations Planning)
1.1.

A list of data and information needed by the Reliability Coordinator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data, as
deemed necessary by the Reliability Coordinator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

M1. The Reliability Coordinator shall make available its dated, current, in force
documented specification for data.

Draft 1 of IRO-010-3
October 2019

Page 1 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

R2.

The Reliability Coordinator shall distribute its data specification to entities that have
data required by the Reliability Coordinator’s Operational Planning Analyses, Realtime monitoring, and Real-time Assessments. (Violation Risk Factor: Low) (Time
Horizon: Operations Planning)

M2. The Reliability Coordinator shall make available evidence that it has distributed its
data specification to entities that have data required by the Reliability Coordinator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments. This
evidence could include but is not limited to web postings with an electronic notice of
the posting, dated operator logs, voice recordings, postal receipts showing the
recipient, date and contents, or e-mail records.
R3.

Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R2 shall satisfy the obligations of the
documented specifications using: (Violation Risk Factor: Medium) (Time Horizon:
Operations Planning, Same-Day Operations, Real-time Operations)
3.1 A mutually agreeable format
3.2 A mutually agreeable process for resolving data conflicts
3.3 A mutually agreeable security protocol

M3. The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Reliability Coordinator, Transmission Operator, Transmission Owner, and
Distribution Provider receiving a data specification in Requirement R2 shall make
available evidence that it satisfied the obligations of the documented specification
using the specified criteria. Such evidence could include but is not limited to
electronic or hard copies of data transmittals or attestations of receiving entities.

Draft 1 of IRO-010-3
October 2019

Page 2 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

C. Compliance
1.

Compliance Monitoring Process
1.1.

Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2

Compliance Monitoring and Assessment Processes

As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment
Processes” refers to the identification of the processes that will be used to evaluate
data or information for the purpose of assessing performance or outcomes with the
associated reliability standard.
1.3.

Data Retention

The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
shall each keep data or evidence to show compliance as identified below unless
directed by its Compliance Enforcement Authority to retain specific evidence for a
longer period of time as part of an investigation:
The Reliability Coordinator shall retain its dated, current, in force documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments for Requirement R1,
Measure M1 as well as any documents in force since the last compliance audit.
The Reliability Coordinator shall keep evidence for three calendar years that it has
distributed its data specification to entities that have data required by the Reliability
Coordinator’s Operational Planning Analyses, Real-time monitoring, and Real-time
Assessments for Requirement R2, Measure M2.
Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
receiving a data specification shall retain evidence for the most recent 90-calendar
days that it has satisfied the obligations of the documented specifications in
accordance with Requirement R3 and Measurement M3.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.

Additional Compliance Information

None.

Draft 1 of IRO-010-3
October 2019

Page 3 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Table of Compliance Elements
R#

R1

Time
Horizon

VRF

Operations
Planning

Low

Violation Severity Levels
Lower

Moderate

High

Severe

The Reliability
Coordinator did not
include one of the
parts (Part 1.1 through
Part 1.4) of the
documented
specification for the
data necessary for it to
perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did
not include three
of the parts (Part
1.1 through Part
1.4) of the
documented
specification for
the data necessary
for it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did not
include any of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.
OR,
The Reliability
Coordinator did not
have a documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time

Draft 1 of IRO-010-3
October 2019

Page 4 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

R#

Time
Horizon

VRF

Violation Severity Levels
Lower

Moderate

High

Severe
monitoring, and
Real-time
Assessments.

For the Requirement R2 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to the
left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity has
just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R2

Operations
Planning

Draft 1 of IRO-010-3
October 2019

Low

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
one entity, or 5% or
less of the entities,
whichever is greater,
that have data
required by the
Reliability
Coordinator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
two entities, or more
than 5% and less
than or equal to 10%
of the reliability
entities, whichever is
greater, that have
data required by the
Reliability
Coordinator’s
Operational Planning
Analyses, and Realtime monitoring, and
Real-time

The Reliability
Coordinator did
not distribute its
data specification
as developed in
Requirement R1 to
three entities, or
more than 10%
and less than or
equal to 15% of the
reliability entities,
whichever is
greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
four or more
entities, or more
than 15% of the
entities, whichever
is greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time

Page 5 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

R#

R3

Time
Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

Draft 1 of IRO-010-3
October 2019

VRF

Violation Severity Levels
Lower

Medium

The responsible entity
receiving a data
specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for data
but failed to follow
one of the criteria
shown in Parts 3.1 –
3.3.

Moderate

High

Severe

Assessments.

monitoring, and
Real-time
Assessments.

Assessments.

The responsible
entity receiving a
data specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow two of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification
in Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow any of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification in
Requirement R2 did
not satisfy the
obligations of the
documented
specifications for
data.

Page 6 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

D. Regional Variances
None
E. Interpretations
None
F. Associated Documents
None
Version History
Version

Date

Action

Change Tracking

1

October 17, 2008

Adopted by Board of Trustees

New

1a

August 5, 2009

Added Appendix 1: Interpretation of
R1.2 and R3 as approved by Board of
Trustees

Addition

1a

March 17, 2011

Order issued by FERC approving IRO010-1a (approval effective 5/23/11)

1a
2

November 19, 2013 Updated VRFs based on June 24, 2013
approval
Revisions pursuant to Project 2014-03
April 2014

2

November 13, 2014

Adopted by NERC Board of Trustees

2

November 19, 2015

FERC approved IRO-010-2. Docket No.
RM15-16-000
Adopted by NERC Board of Trustees

3

Draft 1 of IRO-010-3
October 2019

Revisions under Project
2014-03

Page 7 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Guidelines and Technical Basis
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 adoption, the text from the rationale
text boxes was moved to this section.
Rationale for Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to result
in an appropriate level of situational awareness. Some examples include: 1) analyzing phase
angles which may result in the implementation of an Operating Plan to adjust generation or
curtail transactions so that a Transmission facility may be returned to service, or 2) evaluating
the impact of a modified Contingency resulting from the status change of a Special Protection
Scheme from enabled/in-service to disabled/out-of-service.
Rationale for Applicability Changes:
Changes were made to applicability based on IRO FYRT recommendation to address the need for
UVLS and UFLS information in the data specification.
The Interchange Authority was removed because activities in the Coordinate Interchange
standards are performed by software systems and not a responsible entity. The software, not a
functional entity, performs the task of accepting and disseminating interchange data between
entities. The Balancing Authority is the responsible functional entity for these tasks.
The Planning Coordinator and Transmission Planner were removed from Draft 2 as those entities
would not be involved in a data specification concept as outlined in this standard.
Rationale:
Proposed Requirement R1, Part 1.1:
Is in response to issues raised in NOPR paragraph 67 on the need for obtaining non-BES and
external network data necessary for the Reliability Coordinator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2:
Is in response to NOPR paragraph 78 on relay data.
Proposed Requirement R3, Part 3.3:

Draft 1 of IRO-010-3
October 2019

Page 8 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Is in response to NOPR paragraph 92 where concerns were raised about data exchange through
secured networks.
Corresponding changes have been made to proposed TOP-003-3.

Draft 1 of IRO-010-3
October 2019

Page 9 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

A. Introduction
1. Title:

Reliability Coordinator Data Specification and Collection

2. Number: IRO-010-32
3. Purpose: To prevent instability, uncontrolled separation, or Cascading outages that
adversely impact reliability, by ensuring the Reliability Coordinator has the data it needs
to monitor and assess the operation of its Reliability Coordinator Area.
4. Applicability
4.1. Reliability Coordinator.
4.2. Balancing Authority.
4.3. Generator Owner.
4.4. Generator Operator.
4.5. Load-Serving Entity.
4.6.4.5.

Transmission Operator.

4.7.4.6.

Transmission Owner.

4.8.4.7.

Distribution Provider.

5. Proposed Effective Date:
See Implementation Plan.
6. Background
See Project 2014-03 project page.
B. Requirements
R1.

The Reliability Coordinator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include but not be limited to:
(Violation Risk Factor: Low) (Time Horizon: Operations Planning)
1.1.

A list of data and information needed by the Reliability Coordinator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data, as
deemed necessary by the Reliability Coordinator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

Page 1 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

M1. The Reliability Coordinator shall make available its dated, current, in force
documented specification for data.
R2.

The Reliability Coordinator shall distribute its data specification to entities that have
data required by the Reliability Coordinator’s Operational Planning Analyses, Realtime monitoring, and Real-time Assessments. (Violation Risk Factor: Low) (Time
Horizon: Operations Planning)

M2. The Reliability Coordinator shall make available evidence that it has distributed its
data specification to entities that have data required by the Reliability Coordinator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments. This
evidence could include but is not limited to web postings with an electronic notice of
the posting, dated operator logs, voice recordings, postal receipts showing the
recipient, date and contents, or e-mail records.
R3.

Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Operator, Transmission Owner, and
Distribution Provider receiving a data specification in Requirement R2 shall satisfy the
obligations of the documented specifications using: (Violation Risk Factor: Medium)
(Time Horizon: Operations Planning, Same-Day Operations, Real-time Operations)
3.1 A mutually agreeable format
3.2 A mutually agreeable process for resolving data conflicts
3.3 A mutually agreeable security protocol

M3. The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Reliability Coordinator, Transmission Operator,
Transmission Owner, and Distribution Provider receiving a data specification in
Requirement R2 shall make available evidence that it satisfied the obligations of the
documented specification using the specified criteria. Such evidence could include
but is not limited to electronic or hard copies of data transmittals or attestations of
receiving entities.
C. Compliance
1.

Compliance Monitoring Process
1.1.

Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2

Compliance Monitoring and Assessment Processes

As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment
Processes” refers to the identification of the processes that will be used to evaluate

Page 2 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

data or information for the purpose of assessing performance or outcomes with the
associated reliability standard.
1.3.

Data Retention

The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Operator, Transmission Owner, and
Distribution Provider shall each keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to retain
specific evidence for a longer period of time as part of an investigation:
The Reliability Coordinator shall retain its dated, current, in force documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments for Requirement R1,
Measure M1 as well as any documents in force since the last compliance audit.
The Reliability Coordinator shall keep evidence for three calendar years that it has
distributed its data specification to entities that have data required by the Reliability
Coordinator’s Operational Planning Analyses, Real-time monitoring, and Real-time
Assessments for Requirement R2, Measure M2.
Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Interchange Authority, Load-Serving Entity, Transmission Operator,
Transmission Owner, and Distribution Provider receiving a data specification shall
retain evidence for the most recent 90-calendar days that it has satisfied the
obligations of the documented specifications in accordance with Requirement R3
and Measurement M3.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.

Additional Compliance Information

None.

Page 3 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

Table of Compliance Elements
R#

R1

Time
Horizon

VRF

Operations
Planning

Low

Violation Severity Levels
Lower

Moderate

High

Severe

The Reliability
Coordinator did not
include one of the
parts (Part 1.1 through
Part 1.4) of the
documented
specification for the
data necessary for it to
perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did
not include three
of the parts (Part
1.1 through Part
1.4) of the
documented
specification for
the data necessary
for it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did not
include any of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.
OR,
The Reliability
Coordinator did not
have a documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time

Page 4 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

R#

Time
Horizon

VRF

Violation Severity Levels
Lower

Moderate

High

Severe
monitoring, and
Real-time
Assessments.

For the Requirement R2 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to the
left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity has
just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R2

Operations
Planning

Low

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
one entity, or 5% or
less of the entities,
whichever is greater,
that have data
required by the
Reliability
Coordinator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
two entities, or more
than 5% and less
than or equal to 10%
of the reliability
entities, whichever is
greater, that have
data required by the
Reliability
Coordinator’s
Operational Planning
Analyses, and Realtime monitoring, and
Real-time

The Reliability
Coordinator did
not distribute its
data specification
as developed in
Requirement R1 to
three entities, or
more than 10%
and less than or
equal to 15% of the
reliability entities,
whichever is
greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
four or more
entities, or more
than 15% of the
entities, whichever
is greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time

Page 5 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

R#

R3

Time
Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

VRF

Violation Severity Levels
Lower

Medium

The responsible entity
receiving a data
specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for data
but failed to follow
one of the criteria
shown in Parts 3.1 –
3.3.

Moderate

High

Severe

Assessments.

monitoring, and
Real-time
Assessments.

Assessments.

The responsible
entity receiving a
data specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow two of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification
in Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow any of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification in
Requirement R2 did
not satisfy the
obligations of the
documented
specifications for
data.

Page 6 of 9

Standard IRO-010-3 — Reliability Coordinator Data Specification and CollectionStandard
IRO-010-2 — Guidelines and Technical Basis

D. Regional Variances
None
E. Interpretations
None
F. Associated Documents
None
Version History
Version

Date

Action

Change Tracking

1

October 17, 2008

Adopted by Board of Trustees

New

1a

August 5, 2009

Added Appendix 1: Interpretation of
R1.2 and R3 as approved by Board of
Trustees

Addition

1a

March 17, 2011

Order issued by FERC approving IRO010-1a (approval effective 5/23/11)

1a
2

November 19, 2013 Updated VRFs based on June 24, 2013
approval
Revisions pursuant to Project 2014-03
April 2014

2

November 13, 2014

Adopted by NERC Board of Trustees

2

November 19, 2015

FERC approved IRO-010-2. Docket No.
RM15-16-000
Adopted by NERC Board of Trustees

3

Revisions under Project
2014-03

Page 7 of 9

Standard IRO-010-3 — Reliability Coordinator Data Specification and CollectionStandard
IRO-010-2 — Guidelines and Technical Basis

Guidelines and Technical Basis
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 adoption, the text from the rationale
text boxes was moved to this section.
Rationale for Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to result
in an appropriate level of situational awareness. Some examples include: 1) analyzing phase
angles which may result in the implementation of an Operating Plan to adjust generation or
curtail transactions so that a Transmission facility may be returned to service, or 2) evaluating
the impact of a modified Contingency resulting from the status change of a Special Protection
Scheme from enabled/in-service to disabled/out-of-service.
Rationale for Applicability Changes:
Changes were made to applicability based on IRO FYRT recommendation to address the need for
UVLS and UFLS information in the data specification.
The Interchange Authority was removed because activities in the Coordinate Interchange
standards are performed by software systems and not a responsible entity. The software, not a
functional entity, performs the task of accepting and disseminating interchange data between
entities. The Balancing Authority is the responsible functional entity for these tasks.
The Planning Coordinator and Transmission Planner were removed from Draft 2 as those entities
would not be involved in a data specification concept as outlined in this standard.
Rationale:
Proposed Requirement R1, Part 1.1:
Is in response to issues raised in NOPR paragraph 67 on the need for obtaining non-BES and
external network data necessary for the Reliability Coordinator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2:
Is in response to NOPR paragraph 78 on relay data.
Proposed Requirement R3, Part 3.3:
Page 8 of 9

Standard IRO-010-3 — Reliability Coordinator Data Specification and CollectionStandard
IRO-010-2 — Guidelines and Technical Basis

Is in response to NOPR paragraph 92 where concerns were raised about data exchange through
secured networks.
Corresponding changes have been made to proposed TOP-003-3.

Page 9 of 9

MOD-031-3 — Demand and Energy Data

A. Introduction
1.

Title: Demand and Energy Data

2.

Number:

3.

Purpose: To provide authority for applicable entities to collect Demand, energy
and related data to support reliability studies and assessments and to enumerate the
responsibilities and obligations of requestors and respondents of that data.

4.

Applicability:

MOD-031-3

4.1. Functional Entities:
4.1.1 Planning Coordinator
4.1.2 Transmission Planner
4.1.3 Balancing Authority
4.1.4 Resource Planner
4.1.5 Distribution Provider
5.

Effective Date
5.1. See Implementation Plan.

6.

Background:
To ensure that various forms of historical and forecast Demand and energy data and
information is available to the parties that perform reliability studies and
assessments, authority is needed to collect the applicable data.
The collection of Demand, Net Energy for Load and Demand Side Management data
requires coordination and collaboration between Planning Coordinators, Transmission
and Resource Planners, and Distribution Providers. Ensuring that planners and
operators have access to complete and accurate load forecasts – as well as the
supporting methods and assumptions used to develop these forecasts – enhances the
reliability of the Bulk Electric System. Consistent documenting and information
sharing activities will also improve efficient planning practices and support the
identification of needed system reinforcements. Furthermore, collection of actual
Demand and Demand Side Management performance during the prior year will allow
for comparison to prior forecasts and further contribute to enhanced accuracy of load
forecasting practices.
Data provided under this standard is generally considered confidential by Planning
Coordinators and Balancing Authorities receiving the data. Furthermore, data
reported to a Regional Entity is subject to the confidentiality provisions in Section
1500 of the North American Electric Reliability Corporation Rules of Procedure and is
typically aggregated with data of other functional entities in a non-attributable
manner. While this standard allows for the sharing of data necessary to perform
certain reliability studies and assessments, any data received under this standard for

Draft 1 of MOD-031-3
October 2019

Page 1 of 11

MOD-031-3 — Demand and Energy Data

which an applicable entity has made a claim of confidentiality should be maintained
as confidential by the receiving entity.
B. Requirements and Measures
R1.

Each Planning Coordinator or Balancing Authority that identifies a need for the
collection of Total Internal Demand, Net Energy for Load, and Demand Side
Management data shall develop and issue a data request to the applicable entities in
its area. The data request shall include: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
1.1. A list of Transmission Planners, Balancing Authorities, and Distribution Providers
that are required to provide the data (“Applicable Entities”).
1.2. A timetable for providing the data. (A minimum of 30 calendar days must be
allowed for responding to the request).
1.3. A request to provide any or all of the following actual data, as necessary:
1.3.1. Integrated hourly Demands in megawatts for the prior calendar year.
1.3.2. Monthly and annual integrated peak hour Demands in megawatts for the
prior calendar year.
1.3.2.1.

If the annual peak hour actual Demand varies due to weatherrelated conditions (e.g., temperature, humidity or wind
speed), the Applicable Entity shall also provide the weather
normalized annual peak hour actual Demand for the prior
calendar year.

1.3.3. Monthly and annual Net Energy for Load in gigawatthours for the prior
calendar year.
1.3.4. Monthly and annual peak hour controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator in megawatts for the prior calendar year. Three values shall be
reported for each hour: 1) the committed megawatts (the amount under
control or supervision), 2) the dispatched megawatts (the amount, if any,
activated for use by the System Operator), and 3) the realized megawatts
(the amount of actual demand reduction).
1.4. A request to provide any or all of the following forecast data, as necessary:
1.4.1. Monthly peak hour forecast Total Internal Demands in megawatts for the
next two calendar years.
1.4.2. Monthly forecast Net Energy for Load in gigawatthours for the next two
calendar years.
1.4.3. Peak hour forecast Total Internal Demands (summer and winter) in
megawatts for ten calendar years into the future.
Draft 1 of MOD-031-3
October 2019

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MOD-031-3 — Demand and Energy Data

1.4.4. Annual forecast Net Energy for Load in gigawatthours for ten calendar
years into the future.
1.4.5. Total and available peak hour forecast of controllable and dispatchable
Demand Side Management (summer and winter), in megawatts, under
the control or supervision of the System Operator for ten calendar years
into the future.
1.5. A request to provide any or all of the following summary explanations, as
necessary,:
1.5.1. The assumptions and methods used in the development of aggregated
Peak Demand and Net Energy for Load forecasts.
1.5.2. The Demand and energy effects of controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator.
1.5.3. How Demand Side Management is addressed in the forecasts of its Peak
Demand and annual Net Energy for Load.
1.5.4. How the controllable and dispatchable Demand Side Management
forecast compares to actual controllable and dispatchable Demand Side
Management for the prior calendar year and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
1.5.5. How the peak Demand forecast compares to actual Demand for the prior
calendar year with due regard to any relevant weather-related variations
(e.g., temperature, humidity, or wind speed) and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
M1. The Planning Coordinator or Balancing Authority shall have a dated data request,
either in hardcopy or electronic format, in accordance with Requirement R1.
R2.

Each Applicable Entity identified in a data request shall provide the data requested by
its Planning Coordinator or Balancing Authority in accordance with the data request
issued pursuant to Requirement R1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

M2. Each Applicable Entity shall have evidence, such as dated e-mails or dated transmittal
letters that it provided the requested data in accordance with Requirement R2.
R3.

The Planning Coordinator or the Balancing Authority shall provide the data listed
under Requirement R1 Parts 1.3 through 1.5 for their area to the applicable Regional
Entity within 75 calendar days of receiving a request for such data, unless otherwise
agreed upon by the parties. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]

M3. Each Planning Coordinator or Balancing Authority, shall have evidence, such as dated
e-mails or dated transmittal letters that it provided the data requested by the
applicable Regional Entity in accordance with Requirement R3.
Draft 1 of MOD-031-3
October 2019

Page 3 of 11

MOD-031-3 — Demand and Energy Data

R4.

Any Applicable Entity shall, in response to a written request for the data included in
parts 1.3-1.5 of Requirement R1 from a Planning Coordinator, Balancing Authority,
Transmission Planner or Resource Planner with a demonstrated need for such data in
order to conduct reliability assessments of the Bulk Electric System, provide or
otherwise make available that data to the requesting entity. This requirement does
not modify an entity’s obligation pursuant to Requirement R2 to respond to data
requests issued by its Planning Coordinator or Balancing Authority pursuant to
Requirement R1. Unless otherwise agreed upon, the Applicable Entity: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
•

shall not be required to alter the format in which it maintains or uses the data;

•

shall provide the requested data within 45 calendar days of the written
request, subject to part 4.1 of this requirement; unless providing the
requested data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements

4.1. If the Applicable Entity does not provide data requested because (1) the
requesting entity did not demonstrate a reliability need for the data; or (2)
providing the data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements, the Applicable Entity shall, within 30
calendar days of the written request, provide a written response to the
requesting entity specifying the data that is not being provided and on what
basis.
M4. Each Applicable Entity identified in Requirement R4 shall have evidence such as dated
e-mails or dated transmittal letters that it provided the data requested or provided a
written response specifying the data that is not being provided and the basis for not
providing the data in accordance with Requirement R4.

Draft 1 of MOD-031-3
October 2019

Page 4 of 11

MOD-031-3 — Demand and Energy Data

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The Applicable Entity shall keep data or evidence to show compliance with
Requirements R1 through R4, and Measures M1 through M4, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an Applicable Entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Draft 1 of MOD-031-3
October 2019

Page 5 of 11

MOD-031-3 — Demand and Energy Data

Table of Compliance Elements
R#

Time Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

N/A

N/A

N/A

The Planning Coordinator
or Balancing Authority
developed and issued a
data request but failed to
include either the entity(s)
necessary to provide the
data or the timetable for
providing the data.

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.3.1 through part
1.3.4

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.4.1 through part
1.4.5

R1

Long-term
Planning

Medium

R2

Long-term
Planning

Medium The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide all of the
data requested in
Requirement R1 part
1.5.1 through part
1.5.5

Draft 1 of MOD-031-3
October 2019

High VSL

Severe VSL

OR

Page 6 of 11

MOD-031-3 — Demand and Energy Data

did so after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 6 days
after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

R3

Long-term
Planning

Draft 1 of MOD-031-3
October 2019

Medium The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 75 days

1.4.1 through part
1.4.5

1.4.1 through part
1.4.5

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but
did so 6 days after the
date indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 11
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Applicable Entity, as
defined in the data request
The Applicable Entity, developed in Requirement
R1, failed to provide the
as defined in the data
data requested in the
request developed in
timetable provided
Requirement R1,
pursuant to Requirement
provided the data
R1 prior to 16 days after
requested in
the date indicated in the
Requirement R1, but
timetable provided
did so 11 days after
pursuant to Requirement
the date indicated in
the timetable provided R1 part 1.2.
pursuant to
Requirement R1 part
1.2 but prior to 15
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 80 days

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 85 days

The Planning Coordinator
or Balancing Authority, in
response to a request by
the Regional Entity, failed
to make available the data
requested prior to 91 days

Page 7 of 11

MOD-031-3 — Demand and Energy Data

R4

Long-term
Planning

Draft 1 of MOD-031-3
October 2019

from the date of
request but prior to 81
days from the date of
the request.

from the date of
request but prior to 86
days from the date of
the request.

from the date of
request but prior to 91
days from the date of
the request.

or more from the date of
the request.

Medium The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
45 days from the date
of request but prior to
51 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
50 days from the date
of request but prior to
56 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
55 days from the date
of request but prior to
61 days from the date
of the request

The Applicable Entity failed
to provide or otherwise
make available the data to
the requesting entity
within 60 days from the
date of the request

OR

OR

OR

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 30 days of the
written request but
prior to 36 days of the
written resquest.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 35 days of the
written request but
prior to 41 days of the
written resquest.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 40 days of the
written request but
prior to 46 days of the
written resquest.

OR
The Applicable Entity that
is not providing the data
requested failed to provide
a written response
specifying the data that is
not being provided and on
what basis within 45 days
of the written resquest.

Page 8 of 11

MOD-031-3 — Demand and Energy Data

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

Action

1

May 6, 2014

1

February 19,
2015

Adopted by the NERC Board
of Trustees
FERC order approving MOD031-1

2

November 5,
2015

Adopted by the NERC Board
of Trustees

2

February 18,
2016

FERC order approving MOD031-2. Docket No. RD16-1000

3

Draft 1 of MOD-031-3
October 2019

Change Tracking

Adopted by the NERC Board
of Trustees

Page 9 of 11

Application Guidelines
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:
Rationale for R1: To ensure that when Planning Coordinators (PCs) or Balancing Authorities
(BAs) request data (R1), they identify the entities that must provide the data (Applicable Entity
in part 1.1), the data to be provided (parts 1.3 – 1.5) and the due dates (part 1.2) for the
requested data.
For Requirement R1 part 1.3.2.1, if the Demand does not vary due to weather-related
conditions (e.g., temperature, humidity or wind speed), or the weather assumed in the forecast
was the same as the actual weather, the weather normalized actual Demand will be the same
as the actual demand reported for Requirement R1 part 1.3.2. Otherwise the annual peak hour
weather normalized actual Demand will be different from the actual demand reported for
Requirement R1 part 1.3.2.
Balancing Authorities are included here to reflect a practice in the WECC Region where BAs are
the entity that perform this requirement in lieu of the PC.
Rationale for R2:
This requirement will ensure that entities identified in Requirement R1, as responsible for
providing data, provide the data in accordance with the details described in the data request
developed in accordance with Requirement R1. In no event shall the Applicable Entity be
required to provide data under this requirement that is outside the scope of parts 1.3 - 1.5 of
Requirement R1.
Rationale for R3:
This requirement will ensure that the Planning Coordinator or when applicable, the Balancing
Authority, provides the data requested by the Regional Entity.
Rationale for R4:
This requirement will ensure that the Applicable Entity will make the data requested by the
Planning Coordinator or Balancing Authority in Requirement R1 available to other applicable
entities (Planning Coordinator, Balancing Authority, Transmission Planner or Resource Planner)
unless providing the data would conflict with the Applicable Entity’s confidentiality, regulatory,
or security requirements. The sharing of documentation of the supporting methods and
assumptions used to develop forecasts as well as information-sharing activities will improve the
efficiency of planning practices and support the identification of needed system
reinforcements.
The obligation to share data under Requirement R4 does not supersede or otherwise modify
any of the Applicable Entity’s existing confidentiality obligations. For instance, if an entity is
prohibited from providing any of the requested data pursuant to confidentiality provisions of an
Open Access Transmission Tariff or a contractual arrangement, Requirement R4 does not
Draft 1 of MOD-031-3
October 2019

Page 10 of 11

Application Guidelines

require the Applicable Entity to provide the data to a requesting entity. Rather, under Part 4.1,
the Applicable Entity must simply provide written notification to the requesting entity that it
will not be providing the data and the basis for not providing the data. If the Applicable Entity is
subject to confidentiality obligations that allow the Applicable Entity to share the data only if
certain conditions are met, the Applicable Entity shall ensure that those conditions are met
within the 45-day time period provided in Requirement R4, communicate with the requesting
entity regarding an extension of the 45-day time period so as to meet all those conditions, or
provide justification under Part 4.1 as to why those conditions cannot be met under the
circumstances.

Draft 1 of MOD-031-3
October 2019

Page 11 of 11

MOD-031-2 3 — Demand and Energy Data

A. Introduction
1.

Title: Demand and Energy Data

2.

Number:

3.

Purpose: To provide authority for applicable entities to collect Demand, energy
and related data to support reliability studies and assessments and to enumerate the
responsibilities and obligations of requestors and respondents of that data.

4.

Applicability:

MOD-031-23

4.1. Functional Entities:
4.1.1 Planning Authority and Planning Coordinator (hereafter collectively
referred to as the “Planning Coordinator”)
4.1.1 This proposed standard combines “Planning Authority” with “Planning
Coordinator” in the list of applicable functional entities. The NERC
Functional Model lists “Planning Coordinator” while the registration
criteria list “Planning Authority,” and they are not yet synchronized. Until
that occurs, the proposed standard applies to both “Planning Authority”
and “Planning Coordinator.”
4.1.2 Transmission Planner
4.1.3 Balancing Authority
4.1.4 Resource Planner
4.1.5 Load-Serving Entity
4.1.64.1.5
5.

Distribution Provider

Effective Date
5.1. See the MOD-031-2 Implementation Plan.

6.

Background:
To ensure that various forms of historical and forecast Demand and energy data and
information is available to the parties that perform reliability studies and
assessments, authority is needed to collect the applicable data.
The collection of Demand, Net Energy for Load and Demand Side Management data
requires coordination and collaboration between Planning Authorities (Planning
Coordinators), Transmission and Resource Planners, Load-Serving Entities and
Distribution Providers. Ensuring that planners and operators have access to complete
and accurate load forecasts – as well as the supporting methods and assumptions
used to develop these forecasts – enhances the reliability of the Bulk Electric System.
Consistent documenting and information sharing activities will also improve efficient
planning practices and support the identification of needed system reinforcements.
Furthermore, collection of actual Demand and Demand Side Management

Page 1 of 11

MOD-031-2 3 — Demand and Energy Data

performance during the prior year will allow for comparison to prior forecasts and
further contribute to enhanced accuracy of load forecasting practices.
Data provided under this standard is generally considered confidential by Planning
Coordinators and Balancing Authorities receiving the data. Furthermore, data
reported to a Regional Entity is subject to the confidentiality provisions in Section
1500 of the North American Electric Reliability Corporation Rules of Procedure and is
typically aggregated with data of other functional entities in a non-attributable
manner. While this standard allows for the sharing of data necessary to perform
certain reliability studies and assessments, any data received under this standard for
which an applicable entity has made a claim of confidentiality should be maintained
as confidential by the receiving entity.
B. Requirements and Measures
R1.

Each Planning Coordinator or Balancing Authority that identifies a need for the
collection of Total Internal Demand, Net Energy for Load, and Demand Side
Management data shall develop and issue a data request to the applicable entities in
its area. The data request shall include: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
1.1. A list of Transmission Planners, Balancing Authorities, Load Serving Entities, and
Distribution Providers that are required to provide the data (“Applicable
Entities”).
1.2. A timetable for providing the data. (A minimum of 30 calendar days must be
allowed for responding to the request).
1.3. A request to provide any or all of the following actual data, as necessary:
1.3.1. Integrated hourly Demands in megawatts for the prior calendar year.
1.3.2. Monthly and annual integrated peak hour Demands in megawatts for the
prior calendar year.
1.3.2.1.

If the annual peak hour actual Demand varies due to weatherrelated conditions (e.g., temperature, humidity or wind
speed), the Applicable Entity shall also provide the weather
normalized annual peak hour actual Demand for the prior
calendar year.

1.3.3. Monthly and annual Net Energy for Load in gigawatthours for the prior
calendar year.
1.3.4. Monthly and annual peak hour controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator in megawatts for the prior calendar year. Three values shall be
reported for each hour: 1) the committed megawatts (the amount under
control or supervision), 2) the dispatched megawatts (the amount, if any,

Page 2 of 11

MOD-031-2 3 — Demand and Energy Data

activated for use by the System Operator), and 3) the realized megawatts
(the amount of actual demand reduction).
1.4. A request to provide any or all of the following forecast data, as necessary:
1.4.1. Monthly peak hour forecast Total Internal Demands in megawatts for the
next two calendar years.
1.4.2. Monthly forecast Net Energy for Load in gigawatthours for the next two
calendar years.
1.4.3. Peak hour forecast Total Internal Demands (summer and winter) in
megawatts for ten calendar years into the future.
1.4.4. Annual forecast Net Energy for Load in gigawatthours for ten calendar
years into the future.
1.4.5. Total and available peak hour forecast of controllable and dispatchable
Demand Side Management (summer and winter), in megawatts, under
the control or supervision of the System Operator for ten calendar years
into the future.
1.5. A request to provide any or all of the following summary explanations, as
necessary,:
1.5.1. The assumptions and methods used in the development of aggregated
Peak Demand and Net Energy for Load forecasts.
1.5.2. The Demand and energy effects of controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator.
1.5.3. How Demand Side Management is addressed in the forecasts of its Peak
Demand and annual Net Energy for Load.
1.5.4. How the controllable and dispatchable Demand Side Management
forecast compares to actual controllable and dispatchable Demand Side
Management for the prior calendar year and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
1.5.5. How the peak Demand forecast compares to actual Demand for the prior
calendar year with due regard to any relevant weather-related variations
(e.g., temperature, humidity, or wind speed) and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
M1. The Planning Coordinator or Balancing Authority shall have a dated data request,
either in hardcopy or electronic format, in accordance with Requirement R1.
R2.

Each Applicable Entity identified in a data request shall provide the data requested by
its Planning Coordinator or Balancing Authority in accordance with the data request
issued pursuant to Requirement R1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

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MOD-031-2 3 — Demand and Energy Data

M2. Each Applicable Entity shall have evidence, such as dated e-mails or dated transmittal
letters that it provided the requested data in accordance with Requirement R2.
R3.

The Planning Coordinator or the Balancing Authority shall provide the data listed
under Requirement R1 Parts 1.3 through 1.5 for their area to the applicable Regional
Entity within 75 calendar days of receiving a request for such data, unless otherwise
agreed upon by the parties. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]

M3. Each Planning Coordinator or Balancing Authority, shall have evidence, such as dated
e-mails or dated transmittal letters that it provided the data requested by the
applicable Regional Entity in accordance with Requirement R3.
R4.

Any Applicable Entity shall, in response to a written request for the data included in
parts 1.3-1.5 of Requirement R1 from a Planning Coordinator, Balancing Authority,
Transmission Planner or Resource Planner with a demonstrated need for such data in
order to conduct reliability assessments of the Bulk Electric System, provide or
otherwise make available that data to the requesting entity. This requirement does
not modify an entity’s obligation pursuant to Requirement R2 to respond to data
requests issued by its Planning Coordinator or Balancing Authority pursuant to
Requirement R1. Unless otherwise agreed upon, the Applicable Entity: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
•

shall not be required to alter the format in which it maintains or uses the data;

•

shall provide the requested data within 45 calendar days of the written
request, subject to part 4.1 of this requirement; unless providing the
requested data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements

4.1. If the Applicable Entity does not provide data requested because (1) the
requesting entity did not demonstrate a reliability need for the data; or (2)
providing the data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements, the Applicable Entity shall, within 30
calendar days of the written request, provide a written response to the
requesting entity specifying the data that is not being provided and on what
basis.
M4. Each Applicable Entity identified in Requirement R4 shall have evidence such as dated
e-mails or dated transmittal letters that it provided the data requested or provided a
written response specifying the data that is not being provided and the basis for not
providing the data in accordance with Requirement R4.

Page 4 of 11

MOD-031-2 3 — Demand and Energy Data

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The Applicable Entity shall keep data or evidence to show compliance with
Requirements R1 through R4, and Measures M1 through M4, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an Applicable Entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Page 5 of 11

MOD-031-2 3 — Demand and Energy Data

Table of Compliance Elements
R#

Time Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

N/A

N/A

N/A

The Planning Coordinator
or Balancing Authority
developed and issued a
data request but failed to
include either the entity(s)
necessary to provide the
data or the timetable for
providing the data.

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.3.1 through part
1.3.4

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.4.1 through part
1.4.5

R1

Long-term
Planning

Medium

R2

Long-term
Planning

Medium The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide all of the
data requested in
Requirement R1 part
1.5.1 through part
1.5.5

High VSL

Severe VSL

OR

Page 6 of 11

MOD-031-2 3 — Demand and Energy Data

did so after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 6 days
after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

R3

Long-term
Planning

Medium The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 75 days

1.4.1 through part
1.4.5

1.4.1 through part
1.4.5

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but
did so 6 days after the
date indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 11
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Applicable Entity, as
defined in the data request
The Applicable Entity, developed in Requirement
R1, failed to provide the
as defined in the data
data requested in the
request developed in
timetable provided
Requirement R1,
pursuant to Requirement
provided the data
R1 prior to 16 days after
requested in
the date indicated in the
Requirement R1, but
timetable provided
did so 11 days after
pursuant to Requirement
the date indicated in
the timetable provided R1 part 1.2.
pursuant to
Requirement R1 part
1.2 but prior to 15
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 80 days

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 85 days

The Planning Coordinator
or Balancing Authority, in
response to a request by
the Regional Entity, failed
to make available the data
requested prior to 91 days

Page 7 of 11

MOD-031-2 3 — Demand and Energy Data

R4

Long-term
Planning

from the date of
request but prior to 81
days from the date of
the request.

from the date of
request but prior to 86
days from the date of
the request.

from the date of
request but prior to 91
days from the date of
the request.

or more from the date of
the request.

Medium The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
45 days from the date
of request but prior to
51 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
50 days from the date
of request but prior to
56 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
55 days from the date
of request but prior to
61 days from the date
of the request

The Applicable Entity failed
to provide or otherwise
make available the data to
the requesting entity
within 60 days from the
date of the request

OR

OR

OR

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 30 days of the
written request but
prior to 36 days of the
written resquest.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 35 days of the
written request but
prior to 41 days of the
written resquest.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 40 days of the
written request but
prior to 46 days of the
written resquest.

OR
The Applicable Entity that
is not providing the data
requested failed to provide
a written response
specifying the data that is
not being provided and on
what basis within 45 days
of the written resquest.

Page 8 of 11

MOD-031-2 3 — Demand and Energy Data

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

Action

1

May 6, 2014

1

February 19,
2015

Adopted by the NERC Board
of Trustees
FERC order approving MOD031-1

2

November 5,
2015

Adopted by the NERC Board
of Trustees

2

February 18,
2016

FERC order approving MOD031-2. Docket No. RD16-1000

3

Change Tracking

Adopted by the NERC Board
of Trustees

Page 9 of 11

Application Guidelines
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:
Rationale for R1: To ensure that when Planning Coordinators (PCs) or Balancing Authorities
(BAs) request data (R1), they identify the entities that must provide the data (Applicable Entity
in part 1.1), the data to be provided (parts 1.3 – 1.5) and the due dates (part 1.2) for the
requested data.
For Requirement R1 part 1.3.2.1, if the Demand does not vary due to weather-related
conditions (e.g., temperature, humidity or wind speed), or the weather assumed in the forecast
was the same as the actual weather, the weather normalized actual Demand will be the same
as the actual demand reported for Requirement R1 part 1.3.2. Otherwise the annual peak hour
weather normalized actual Demand will be different from the actual demand reported for
Requirement R1 part 1.3.2.
Balancing Authorities are included here to reflect a practice in the WECC Region where BAs are
the entity that perform this requirement in lieu of the PC.
Rationale for R2:
This requirement will ensure that entities identified in Requirement R1, as responsible for
providing data, provide the data in accordance with the details described in the data request
developed in accordance with Requirement R1. In no event shall the Applicable Entity be
required to provide data under this requirement that is outside the scope of parts 1.3 - 1.5 of
Requirement R1.
Rationale for R3:
This requirement will ensure that the Planning Coordinator or when applicable, the Balancing
Authority, provides the data requested by the Regional Entity.
Rationale for R4:
This requirement will ensure that the Applicable Entity will make the data requested by the
Planning Coordinator or Balancing Authority in Requirement R1 available to other applicable
entities (Planning Coordinator, Balancing Authority, Transmission Planner or Resource Planner)
unless providing the data would conflict with the Applicable Entity’s confidentiality, regulatory,
or security requirements. The sharing of documentation of the supporting methods and
assumptions used to develop forecasts as well as information-sharing activities will improve the
efficiency of planning practices and support the identification of needed system
reinforcements.
The obligation to share data under Requirement R4 does not supersede or otherwise modify
any of the Applicable Entity’s existing confidentiality obligations. For instance, if an entity is
prohibited from providing any of the requested data pursuant to confidentiality provisions of an
Open Access Transmission Tariff or a contractual arrangement, Requirement R4 does not

Page 10 of 11

Application Guidelines
require the Applicable Entity to provide the data to a requesting entity. Rather, under Part 4.1,
the Applicable Entity must simply provide written notification to the requesting entity that it
will not be providing the data and the basis for not providing the data. If the Applicable Entity is
subject to confidentiality obligations that allow the Applicable Entity to share the data only if
certain conditions are met, the Applicable Entity shall ensure that those conditions are met
within the 45-day time period provided in Requirement R4, communicate with the requesting
entity regarding an extension of the 45-day time period so as to meet all those conditions, or
provide justification under Part 4.1 as to why those conditions cannot be met under the
circumstances.

Page 11 of 11

MOD-033-2 — Steady-State and Dynamic System Model Validation

A. Introduction
1.

Title: Steady-State and Dynamic System Model Validation

2.

Number:

3.

Purpose:
To establish consistent validation requirements to facilitate the
collection of accurate data and building of planning models to analyze the reliability of
the interconnected transmission system.

4.

Applicability:

MOD-033-2

4.1. Functional Entities:
4.1.1 Planning Coordinator
4.1.2 Reliability Coordinator
4.1.3 Transmission Operator
5.

Effective Date:
See Implementation Plan.

Draft 1 of MOD-033-2
October 2019

MOD-033-2 — Steady-State and Dynamic System Model Validation

B. Requirements and Measures
R1.

Each Planning Coordinator shall implement a documented data validation process
that includes the following attributes: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
1.1. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning power flow model to actual system behavior,
represented by a state estimator case or other Real-time data sources, at least
once every 24 calendar months through simulation;
1.2. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning dynamic model to actual system response, through
simulation of a dynamic local event, at least once every 24 calendar months (use
a dynamic local event that occurs within 24 calendar months of the last dynamic
local event used in comparison, and complete each comparison within 24
calendar months of the dynamic local event). If no dynamic local event occurs
within the 24 calendar months, use the next dynamic local event that occurs;
1.3. Guidelines the Planning Coordinator will use to determine unacceptable
differences in performance under Part 1.1 or 1.2; and
1.4. Guidelines to resolve the unacceptable differences in performance identified
under Part 1.3.

M1. Each Planning Coordinator shall provide evidence that it has a documented validation

process according to Requirement R1 as well as evidence that demonstrates the
implementation of the required components of the process.

R2.

Each Reliability Coordinator and Transmission Operator shall provide actual system
behavior data (or a written response that it does not have the requested data) to any
Planning Coordinator performing validation under Requirement R1 within 30 calendar
days of a written request, such as, but not limited to, state estimator case or other
Real-time data (including disturbance data recordings) necessary for actual system
response validation. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

M2. Each Reliability Coordinator and Transmission Operator shall provide evidence, such

as email notices or postal receipts showing recipient and date that it has distributed
the requested data or written response that it does not have the data, to any Planning
Coordinator performing validation under Requirement R1 within 30 days of a written
request in accordance with Requirement R2; or a statement by the Reliability
Coordinator or Transmission Operator that it has not received notification regarding
data necessary for validation by any Planning Coordinator.

Draft 1 of MOD-033-2
October 2019

MOD-033-2 — Steady-State and Dynamic System Model Validation

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity in their
respective roles of monitoring and enforcing compliance with the NERC
Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance with
Requirements R1 through R2, and Measures M1 through M2, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an applicable entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Refer to Section 3.0 of Appendix 4C of the NERC Rules of Procedure for a list of
compliance monitoring and assessment processes.
1.4. Additional Compliance Information
None

Draft 1 of MOD-033-2
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MOD-033-2 — Steady-State and Dynamic System Model Validation

Table of Compliance Elements
R#

Time Horizon

Violation Severity Levels

VRF
Lower VSL

R1

Long-term
Planning

Medium The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address one of the
four required topics
under Requirement
R1;

High VSL

Severe VSL

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address two of the
four required topics
under Requirement
R1;

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address three of the
four required topics
under Requirement
R1;

The Planning
Coordinator did not
have a validation
process at all or did
not document or
implement any of the
four required topics
under Requirement
R1;

OR

OR

OR

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation within 28
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months;

The Planning
Coordinator did not
validate its portion of
the system in the
power flow model as
required by part 1.1
within 36 calendar
months;

OR

OR

OR
The Planning
Coordinator did not
perform simulation as
Draft 1 of MOD-033-2
October 2019

Moderate VSL

OR

OR
The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 36 calendar

Page 4 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

R#

R2

Time Horizon

Long-term
Planning

Draft 1 of MOD-033-2
October 2019

Violation Severity Levels

VRF

Lower

Lower VSL

Moderate VSL

High VSL

Severe VSL

required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation within 28
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months.

months (or the next
dynamic local event in
cases where there is
more than 24 months
between events).

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Page 5 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

R#

Time Horizon

Violation Severity Levels

VRF
Lower VSL

Moderate VSL

High VSL

Severe VSL

Coordinator within 30
calendar days of the
written request, but
did provide the data
(or written response
that it does not have
the requested data) in
less than or equal to
45 calendar days.

Coordinator within 30
calendar days of the
written request, but
did provide the data
(or written response
that it does not have
the requested data) in
greater than 45
calendar days but less
than or equal to 60
calendar days.

Coordinator within 30
calendar days of the
written request, but
did provide the data
(or written response
that it does not have
the requested data) in
greater than 60
calendar days but less
than or equal to 75
calendar days.

Coordinator within 75
calendar days;
OR
The Reliability
Coordinator or
Transmission Operator
provided a written
response that it does
not have the
requested data, but
actually had the data.

D. Regional Variances
None.

E. Interpretations
None.

F. Associated Documents
None.

Draft 1 of MOD-033-2
October 2019

Page 6 of 10

Application Guidelines

Guidelines and Technical Basis
Requirement R1:
The requirement focuses on the results-based outcome of developing a process for and
performing a validation, but does not prescribe a specific method or procedure for the
validation outside of the attributes specified in the requirement. For further information on
suggested validation procedures, see “Procedures for Validation of Powerflow and Dynamics
Cases” produced by the NERC Model Working Group.
The specific process is left to the judgment of the Planning Coordinator, but the Planning
Coordinator is required to develop and include in its process guidelines for evaluating
discrepancies between actual system behavior or response and expected system performance
for determining whether the discrepancies are unacceptable.
For the validation in part 1.1, the state estimator case or other Real-time data should be taken
as close to system peak as possible. However, other snapshots of the system could be used if
deemed to be more appropriate by the Planning Coordinator. While the requirement specifies
“once every 24 calendar months,” entities are encouraged to perform the comparison on a
more frequent basis.
In performing the comparison required in part 1.1, the Planning Coordinator may consider,
among other criteria:
1. System load;
2. Transmission topology and parameters;
3. Voltage at major buses; and
4. Flows on major transmission elements.
The validation in part 1.1 would include consideration of the load distribution and load power
factors (as applicable) used in the power flow models. The validation may be made using
metered load data if state estimator cases are not available. The comparison of system load
distribution and load power factors shall be made on an aggregate company or power flow
zone level at a minimum but may also be made on a bus by bus, load pocket (e.g., within a
Balancing Authority), or smaller area basis as deemed appropriate by the Planning Coordinator.
The scope of dynamics model validation is intended to be limited, for purposes of part 1.2, to
the Planning Coordinator’s planning area, and the intended emphasis under the requirement is
on local events or local phenomena, not the whole Interconnection.
The validation required in part 1.2 may include simulations that are to be compared with actual
system data and may include comparisons of:
•

Voltage oscillations at major buses

•

System frequency (for events with frequency excursions)

•

Real and reactive power oscillations on generating units and major inter-area ties

Draft 1 of MOD-033-2
October 2019

Application Guidelines

Determining when a dynamic local event might occur may be unpredictable, and because of the
analytic complexities involved in simulation, the time parameters in part 1.2 specify that the
comparison period of “at least once every 24 calendar months” is intended to both provide for
at least 24 months between dynamic local events used in the comparisons and that
comparisons must be completed within 24 months of the date of the dynamic local event used.
This clarification ensures that PCs will not face a timing scenario that makes it impossible to
comply. If the time referred to the completion time of the comparison, it would be possible for
an event to occur in month 23 since the last comparison, leaving only one month to complete
the comparison. With the 30 day timeframe in Requirement R2 for TOPs or RCs to provide
actual system behavior data (if necessary in the comparison), it would potentially be impossible
to complete the comparison within the 24 month timeframe.
In contrast, the requirement language clarifies that the time frame between dynamic local
events used in the comparisons should be within 24 months of each other (or, as specified at
the end of part 1.2, in the event more than 24 months passes before the next dynamic local
event, the comparison should use the next dynamic local event that occurs). Each comparison
must be completed within 24 months of the dynamic local event used. In this manner, the
potential problem with a “month 23” dynamic local event described above is resolved. For
example, if a PC uses for comparison a dynamic local event occurring on day 1 of month 1, the
PC has 24 calendar months from that dynamic local event’s occurrence to complete the
comparison. If the next dynamic event the PC chooses for comparison occurs in month 23, the
PC has 24 months from that dynamic local event’s occurrence to complete the comparison.
Part 1.3 requires the PC to include guidelines in its documented validation process for
determining when discrepancies in the comparison of simulation results with actual system
results are unacceptable. The PC may develop the guidelines required by parts 1.3 and 1.4
itself, reference other established guidelines, or both. For the power flow comparison, as an
example, this could include a guideline the Planning Coordinator will use that flows on 500 kV
lines should be within 10% or 100 MW, whichever is larger. It could be different percentages or
MW amounts for different voltage levels. Or, as another example, the guideline for voltage
comparisons could be that it must be within 1%. But the guidelines the PC includes within its
documented validation process should be meaningful for the Planning Coordinator’s system.
Guidelines for the dynamic event comparison may be less precise. Regardless, the comparison
should indicate that the conclusions drawn from the two results should be consistent. For
example, the guideline could state that the simulation result will be plotted on the same graph
as the actual system response. Then the two plots could be given a visual inspection to see if
they look similar or not. Or a guideline could be defined such that the rise time of the transient
response in the simulation should be within 20% of the rise time of the actual system response.
As for the power flow guidelines, the dynamic comparison criteria should be meaningful for the
Planning Coordinator’s system.
The guidelines the PC includes in its documented validation process to resolve differences in
Part 1.4 could include direct coordination with the data owner, and, if necessary, through the
provisions of MOD-032-1, Requirement R3 (i.e., the validation performed under this
requirement could identify technical concerns with the data). In other words, while this
standard is focused on validation, results of the validation may identify data provided under the
Draft 1 of MOD-033-2
October 2019

Application Guidelines

modeling data standard that needs to be corrected. If a model with estimated data or a generic
model is used for a generator, and the model response does not match the actual response,
then the estimated data should be corrected or a more detailed model should be requested
from the data provider.
While the validation is focused on the Planning Coordinator’s planning area, the model for the
validation should be one that contains a wider area of the Interconnection than the Planning
Coordinator’s area. If the simulations can be made to match the actual system responses by
reasonable changes to the data in the Planning Coordinator’s area, then the Planning
Coordinator should make those changes in coordination with the data provider. However, for
some disturbances, the data in the Planning Coordinator’s area may not be what is causing the
simulations to not match actual responses. These situations should be reported to the Electric
Reliability Organization (ERO). The guidelines the Planning Coordinator includes under Part 1.4
could cover these situations.
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:
In FERC Order No. 693, paragraph 1210, the Commission directed inclusion of “a requirement
that the models be validated against actual system responses.” Furthermore, the Commission
directs in paragraph 1211, “that actual system events be simulated and if the model output is
not within the accuracy required, the model shall be modified to achieve the necessary
accuracy.” Paragraph 1220 similarly directs validation against actual system responses relative
to dynamics system models. In FERC Order 890, paragraph 290, the Commission states that
“the models should be updated and benchmarked to actual events.” Requirement R1 addresses
these directives.
Requirement R1 requires the Planning Coordinator to implement a documented data validation
process to validate data in the Planning Coordinator’s portion of the existing system in the
steady-state and dynamic models to compare performance against expected behavior or
response, which is consistent with the Commission directives. The validation of the full
Interconnection-wide cases is left up to the Electric Reliability Organization (ERO) or its
designees, and is not addressed by this standard. The following items were chosen for the
validation requirement:
A. Comparison of performance of the existing system in a planning power flow model to actual
system behavior; and
B. Comparison of the performance of the existing system in a planning dynamics model to
actual system response.
Implementation of these validations will result in more accurate power flow and dynamic
models. This, in turn, should result in better correlation between system flows and voltages
Draft 1 of MOD-033-2
October 2019

Application Guidelines

seen in power flow studies and the actual values seen by system operators during outage
conditions. Similar improvements should be expected for dynamics studies, such that the
results will more closely match the actual responses of the power system to disturbances.
Validation of model data is a good utility practice, but it does not easily lend itself to Reliability
Standards requirement language. Furthermore, it is challenging to determine specifications for
thresholds of disturbances that should be validated and how they are determined. Therefore,
this requirement focuses on the Planning Coordinator performing validation pursuant to its
process, which must include the attributes listed in parts 1.1 through 1.4, without specifying the
details of “how” it must validate, which is necessarily dependent upon facts and circumstances.
Other validations are best left to guidance rather than standard requirements.
Rationale for R2:
The Planning Coordinator will need actual system behavior data in order to perform the
validations required in R1. The Reliability Coordinator or Transmission Operator may have this
data. Requirement R2 requires the Reliability Coordinator and Transmission Operator to supply
actual system data, if it has the data, to any requesting Planning Coordinator for purposes of
model validation under Requirement R1.
This could also include information the Reliability Coordinator or Transmission Operator has at
a field site. For example, if a PMU or DFR is at a generator site and it is recording the
disturbance, the Reliability Coordinator or Transmission Operator would typically have that
data.

Version History
Version

Date

Action

1

February 6,
2014

Adopted by the NERC Board of
Trustees.

1

May 1, 2014

FERC Order issued approving
MOD-033-1.

2

Draft 1 of MOD-033-2
October 2019

Adopted by the NERC Board of
Trustees.

Change Tracking

Developed as a new
standard for system
validation to address
outstanding directives
from FERC Order No. 693
and recommendations
from several other
sources.

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

A. Introduction
1.

Title: Steady-State and Dynamic System Model Validation

2.

Number:

3.

Purpose:
To establish consistent validation requirements to facilitate the
collection of accurate data and building of planning models to analyze the reliability of
the interconnected transmission system.

4.

Applicability:

MOD-033-21

4.1. Functional Entities:
4.1.1 Planning Authority and Planning Coordinator (hereafter referred to as
“Planning Coordinator”)
4.1.24.1.1
This proposed standard combines “Planning Authority” with
“Planning Coordinator” in the list of applicable functional entities. The
NERC Functional Model lists “Planning Coordinator” while the
registration criteria list “Planning Authority,” and they are not yet
synchronized. Until that occurs, the proposed standard applies to both
Planning Authority and Planning Coordinator.

5.

4.1.34.1.2

Reliability Coordinator

4.1.44.1.3

Transmission Operator

Effective Date:
MOD-033-1 shall become effective on the first day of the first calendar quarter that is
36 months 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 that is 36
months after the date the standard is adopted by the NERC Board of Trustees or as
otherwise provided for in that jurisdiction.See Implementation Plan.

6.

Background:
MOD-033-1 exists in conjunction with MOD-032-1, both of which are related to
system-level modeling and validation. Reliability Standard MOD-032-1 is a
consolidation and replacement of existing MOD-010-0, MOD-011-0, MOD-012-0,
MOD-013-1, MOD-014-0, and MOD-015-0.1, and it requires data submission by
applicable data owners to their respective Transmission Planners and Planning
Coordinators to support the Interconnection-wide case building process in their
Interconnection. Reliability Standard MOD-033-1 is a new standard, and it requires
each Planning Coordinator to implement a documented process to perform model
validation within its planning area.

Page 1 of 12

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

The transition and focus of responsibility upon the Planning Coordinator function in
both standards are driven by several recommendations and FERC directives (to
include several remaining directives from FERC Order No. 693), which are discussed in
greater detail in the rationale sections of the standards. One of the most recent and
significant set of recommendations came from the NERC Planning Committee’s
System Analysis and Modeling Subcommittee (SAMS). SAMS proposed several
improvements to the modeling data standards, to include consolidation of the
standards (that whitepaper is available from the December 2012 NERC Planning
Committee’s agenda package, item 3.4, beginning on page 99, here:
http://www.nerc.com/comm/PC/Agendas%20Highlights%20and%20Minutes%20DL/2
012/2012_Dec_PC%20Agenda.pdf).
The focus of validation in this standard is not Interconnection-wide phenomena, but
on the Planning Coordinator’s portion of the existing system. The Reliability Standard
requires Planning Coordinators to implement a documented data validation process
for power flow and dynamics. For the dynamics validation, the target of validation is
those events that the Planning Coordinator determines are dynamic local events. A
dynamic local event could include such things as closing a transmission line near a
generating plant. A dynamic local event is a disturbance on the power system that
produces some measurable transient response, such as oscillations. It could involve
one small area of the system or a generating plant oscillating against the rest of the
grid. The rest of the grid should not have a significant effect. Oscillations involving
large areas of the grid are not local events. However, a dynamic local event could also
be a subset of a larger disturbance involving large areas of the grid.
B. Requirements and Measures
R1.

Each Planning Coordinator shall implement a documented data validation process
that includes the following attributes: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
1.1. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning power flow model to actual system behavior,
represented by a state estimator case or other Real-time data sources, at least
once every 24 calendar months through simulation;
1.2. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning dynamic model to actual system response, through
simulation of a dynamic local event, at least once every 24 calendar months (use
a dynamic local event that occurs within 24 calendar months of the last dynamic
local event used in comparison, and complete each comparison within 24
calendar months of the dynamic local event). If no dynamic local event occurs
within the 24 calendar months, use the next dynamic local event that occurs;
1.3. Guidelines the Planning Coordinator will use to determine unacceptable
differences in performance under Part 1.1 or 1.2; and

Page 2 of 12

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

1.4. Guidelines to resolve the unacceptable differences in performance identified
under Part 1.3.
M1. Each Planning Coordinator shall provide evidence that it has a documented validation

process according to Requirement R1 as well as evidence that demonstrates the
implementation of the required components of the process.

R2.

Each Reliability Coordinator and Transmission Operator shall provide actual system
behavior data (or a written response that it does not have the requested data) to any
Planning Coordinator performing validation under Requirement R1 within 30 calendar
days of a written request, such as, but not limited to, state estimator case or other
Real-time data (including disturbance data recordings) necessary for actual system
response validation. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

M2. Each Reliability Coordinator and Transmission Operator shall provide evidence, such

as email notices or postal receipts showing recipient and date that it has distributed
the requested data or written response that it does not have the data, to any Planning
Coordinator performing validation under Requirement R1 within 30 days of a written
request in accordance with Requirement R2; or a statement by the Reliability
Coordinator or Transmission Operator that it has not received notification regarding
data necessary for validation by any Planning Coordinator.

Page 3 of 12

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity in their
respective roles of monitoring and enforcing compliance with the NERC
Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance with
Requirements R1 through R2, and Measures M1 through M2, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an applicable entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Refer to Section 3.0 of Appendix 4C of the NERC Rules of Procedure for a list of
compliance monitoring and assessment processes.
1.4. Additional Compliance Information
None

Page 4 of 12

MOD-033-2 — Steady-State and Dynamic System Model Validation

Table of Compliance Elements
R#

Time Horizon

Violation Severity Levels

VRF
Lower VSL

R1

Long-term
Planning

Medium The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address one of the
four required topics
under Requirement
R1;

Moderate VSL

High VSL

Severe VSL

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address two of the
four required topics
under Requirement
R1;

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address three of the
four required topics
under Requirement
R1;

The Planning
Coordinator did not
have a validation
process at all or did
not document or
implement any of the
four required topics
under Requirement
R1;

OR

OR

OR

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation within 28
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months;

The Planning
Coordinator did not
validate its portion of
the system in the
power flow model as
required by part 1.1
within 36 calendar
months;

OR

OR

OR
The Planning
Coordinator did not
perform simulation as

Page 5 of 12

OR

OR
The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 36 calendar

MOD-033-2 — Steady-State and Dynamic System Model Validation

R2

Long-term
Planning

Lower

required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation within 28
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months.

months (or the next
dynamic local event in
cases where there is
more than 24 months
between events).

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 30
calendar days of the
written request, but

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 30
calendar days of the
written request, but

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 30
calendar days of the
written request, but

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 75
calendar days;

Page 6 of 12

MOD-033-2 — Steady-State and Dynamic System Model Validation

did provide the data
(or written response
that it does not have
the requested data) in
less than or equal to
45 calendar days.

did provide the data
(or written response
that it does not have
the requested data) in
greater than 45
calendar days but less
than or equal to 60
calendar days.

did provide the data
(or written response
that it does not have
the requested data) in
greater than 60
calendar days but less
than or equal to 75
calendar days.

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Page 7 of 12

OR
The Reliability
Coordinator or
Transmission Operator
provided a written
response that it does
not have the
requested data, but
actually had the data.

Application Guidelines
Guidelines and Technical Basis
Requirement R1:
The requirement focuses on the results-based outcome of developing a process for and
performing a validation, but does not prescribe a specific method or procedure for the
validation outside of the attributes specified in the requirement. For further information on
suggested validation procedures, see “Procedures for Validation of Powerflow and Dynamics
Cases” produced by the NERC Model Working Group.
The specific process is left to the judgment of the Planning Coordinator, but the Planning
Coordinator is required to develop and include in its process guidelines for evaluating
discrepancies between actual system behavior or response and expected system performance
for determining whether the discrepancies are unacceptable.
For the validation in part 1.1, the state estimator case or other Real-time data should be taken
as close to system peak as possible. However, other snapshots of the system could be used if
deemed to be more appropriate by the Planning Coordinator. While the requirement specifies
“once every 24 calendar months,” entities are encouraged to perform the comparison on a
more frequent basis.
In performing the comparison required in part 1.1, the Planning Coordinator may consider,
among other criteria:
1. System load;
2. Transmission topology and parameters;
3. Voltage at major buses; and
4. Flows on major transmission elements.
The validation in part 1.1 would include consideration of the load distribution and load power
factors (as applicable) used in the power flow models. The validation may be made using
metered load data if state estimator cases are not available. The comparison of system load
distribution and load power factors shall be made on an aggregate company or power flow
zone level at a minimum but may also be made on a bus by bus, load pocket (e.g., within a
Balancing Authority), or smaller area basis as deemed appropriate by the Planning Coordinator.
The scope of dynamics model validation is intended to be limited, for purposes of part 1.2, to
the Planning Coordinator’s planning area, and the intended emphasis under the requirement is
on local events or local phenomena, not the whole Interconnection.
The validation required in part 1.2 may include simulations that are to be compared with actual
system data and may include comparisons of:
•

Voltage oscillations at major buses

•

System frequency (for events with frequency excursions)

•

Real and reactive power oscillations on generating units and major inter-area ties

Page 8 of 12

Application Guidelines
Determining when a dynamic local event might occur may be unpredictable, and because of the
analytic complexities involved in simulation, the time parameters in part 1.2 specify that the
comparison period of “at least once every 24 calendar months” is intended to both provide for
at least 24 months between dynamic local events used in the comparisons and that
comparisons must be completed within 24 months of the date of the dynamic local event used.
This clarification ensures that PCs will not face a timing scenario that makes it impossible to
comply. If the time referred to the completion time of the comparison, it would be possible for
an event to occur in month 23 since the last comparison, leaving only one month to complete
the comparison. With the 30 day timeframe in Requirement R2 for TOPs or RCs to provide
actual system behavior data (if necessary in the comparison), it would potentially be impossible
to complete the comparison within the 24 month timeframe.
In contrast, the requirement language clarifies that the time frame between dynamic local
events used in the comparisons should be within 24 months of each other (or, as specified at
the end of part 1.2, in the event more than 24 months passes before the next dynamic local
event, the comparison should use the next dynamic local event that occurs). Each comparison
must be completed within 24 months of the dynamic local event used. In this manner, the
potential problem with a “month 23” dynamic local event described above is resolved. For
example, if a PC uses for comparison a dynamic local event occurring on day 1 of month 1, the
PC has 24 calendar months from that dynamic local event’s occurrence to complete the
comparison. If the next dynamic event the PC chooses for comparison occurs in month 23, the
PC has 24 months from that dynamic local event’s occurrence to complete the comparison.
Part 1.3 requires the PC to include guidelines in its documented validation process for
determining when discrepancies in the comparison of simulation results with actual system
results are unacceptable. The PC may develop the guidelines required by parts 1.3 and 1.4
itself, reference other established guidelines, or both. For the power flow comparison, as an
example, this could include a guideline the Planning Coordinator will use that flows on 500 kV
lines should be within 10% or 100 MW, whichever is larger. It could be different percentages or
MW amounts for different voltage levels. Or, as another example, the guideline for voltage
comparisons could be that it must be within 1%. But the guidelines the PC includes within its
documented validation process should be meaningful for the Planning Coordinator’s system.
Guidelines for the dynamic event comparison may be less precise. Regardless, the comparison
should indicate that the conclusions drawn from the two results should be consistent. For
example, the guideline could state that the simulation result will be plotted on the same graph
as the actual system response. Then the two plots could be given a visual inspection to see if
they look similar or not. Or a guideline could be defined such that the rise time of the transient
response in the simulation should be within 20% of the rise time of the actual system response.
As for the power flow guidelines, the dynamic comparison criteria should be meaningful for the
Planning Coordinator’s system.
The guidelines the PC includes in its documented validation process to resolve differences in
Part 1.4 could include direct coordination with the data owner, and, if necessary, through the
provisions of MOD-032-1, Requirement R3 (i.e., the validation performed under this
requirement could identify technical concerns with the data). In other words, while this
standard is focused on validation, results of the validation may identify data provided under the
Page 9 of 12

Application Guidelines
modeling data standard that needs to be corrected. If a model with estimated data or a generic
model is used for a generator, and the model response does not match the actual response,
then the estimated data should be corrected or a more detailed model should be requested
from the data provider.
While the validation is focused on the Planning Coordinator’s planning area, the model for the
validation should be one that contains a wider area of the Interconnection than the Planning
Coordinator’s area. If the simulations can be made to match the actual system responses by
reasonable changes to the data in the Planning Coordinator’s area, then the Planning
Coordinator should make those changes in coordination with the data provider. However, for
some disturbances, the data in the Planning Coordinator’s area may not be what is causing the
simulations to not match actual responses. These situations should be reported to the Electric
Reliability Organization (ERO). The guidelines the Planning Coordinator includes under Part 1.4
could cover these situations.
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:
In FERC Order No. 693, paragraph 1210, the Commission directed inclusion of “a requirement
that the models be validated against actual system responses.” Furthermore, the Commission
directs in paragraph 1211, “that actual system events be simulated and if the model output is
not within the accuracy required, the model shall be modified to achieve the necessary
accuracy.” Paragraph 1220 similarly directs validation against actual system responses relative
to dynamics system models. In FERC Order 890, paragraph 290, the Commission states that
“the models should be updated and benchmarked to actual events.” Requirement R1 addresses
these directives.
Requirement R1 requires the Planning Coordinator to implement a documented data validation
process to validate data in the Planning Coordinator’s portion of the existing system in the
steady-state and dynamic models to compare performance against expected behavior or
response, which is consistent with the Commission directives. The validation of the full
Interconnection-wide cases is left up to the Electric Reliability Organization (ERO) or its
designees, and is not addressed by this standard. The following items were chosen for the
validation requirement:
A. Comparison of performance of the existing system in a planning power flow model to actual
system behavior; and
B. Comparison of the performance of the existing system in a planning dynamics model to
actual system response.

Page 10 of 12

Application Guidelines
Implementation of these validations will result in more accurate power flow and dynamic
models. This, in turn, should result in better correlation between system flows and voltages
seen in power flow studies and the actual values seen by system operators during outage
conditions. Similar improvements should be expected for dynamics studies, such that the
results will more closely match the actual responses of the power system to disturbances.
Validation of model data is a good utility practice, but it does not easily lend itself to Reliability
Standards requirement language. Furthermore, it is challenging to determine specifications for
thresholds of disturbances that should be validated and how they are determined. Therefore,
this requirement focuses on the Planning Coordinator performing validation pursuant to its
process, which must include the attributes listed in parts 1.1 through 1.4, without specifying the
details of “how” it must validate, which is necessarily dependent upon facts and circumstances.
Other validations are best left to guidance rather than standard requirements.
Rationale for R2:
The Planning Coordinator will need actual system behavior data in order to perform the
validations required in R1. The Reliability Coordinator or Transmission Operator may have this
data. Requirement R2 requires the Reliability Coordinator and Transmission Operator to supply
actual system data, if it has the data, to any requesting Planning Coordinator for purposes of
model validation under Requirement R1.
This could also include information the Reliability Coordinator or Transmission Operator has at
a field site. For example, if a PMU or DFR is at a generator site and it is recording the
disturbance, the Reliability Coordinator or Transmission Operator would typically have that
data.

Version History
Version

Date

Action

1

February 6,
2014

Adopted by the NERC Board of
Trustees.

1

May 1, 2014

FERC Order issued approving
MOD-033-1.

Change Tracking
Developed as a new
standard for system
validation to address
outstanding directives
from FERC Order No. 693
and recommendations
from several other
sources.

Page 11 of 12

Application Guidelines
2

Adopted by the NERC Board of
Trustees.

Page 12 of 12

NUC-001-4— Nuclear Plant Interface Coordination

A. Introduction
1.

Title:

Nuclear Plant Interface Coordination

2.

Number:

NUC-001-4

3.

Purpose: This standard requires coordination between Nuclear Plant Generator
Operators and Transmission Entities for the purpose of ensuring nuclear plant safe
operation and shutdown.

4.

Applicability:
4.1. Functional Entities:
4.1.1 Nuclear Plant Generator Operators.
4.2. Transmission Entities shall mean all entities that are responsible for providing
services related to Nuclear Plant Interface Requirements (NPIRs). Such entities
may include one or more of the following:
4.2.1 Transmission Operators.
4.2.2 Transmission Owners.
4.2.3 Transmission Planners.
4.2.4 Transmission Service Providers.
4.2.5 Balancing Authorities.
4.2.6 Reliability Coordinators.
4.2.7 Planning Coordinators.
4.2.8 Distribution Providers.
4.2.9 Generator Owners.
4.2.10 Generator Operators.

5. Proposed Effective Date:
See Implementation Plan.

Draft 1 of NUC-001-4
October 2019

Page 1 of 16

NUC-001-4— Nuclear Plant Interface Coordination

B. Requirements and Measures
R1.

The Nuclear Plant Generator Operator shall provide the proposed NPIRs in writing to
the applicable Transmission Entities and shall verify receipt. [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning ]

M1. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, provide a copy of the transmittal and receipt of transmittal of
the proposed NPIRs to the responsible Transmission Entities.
R2.

The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
have in effect one or more Agreements 1 that include mutually agreed to NPIRs and
document how the Nuclear Plant Generator Operator and the applicable Transmission
Entities shall address and implement these NPIRs. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning ]

M2. The Nuclear Plant Generator Operator and each Transmission Entity shall each have a
copy of the currently effective Agreement(s) which document how the Nuclear Plant
Generator Operator and the applicable Transmission Entities address and implement
the NPIRs available for inspection upon request of the Compliance Enforcement
Authority.
R3.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall incorporate the NPIRs into their planning analyses of the
electric system and shall communicate the results of these analyses to the Nuclear
Plant Generator Operator.: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning ]

M3. Each Transmission Entity responsible for planning analyses in accordance with the
Agreement shall, upon request of the Compliance Enforcement Authority, provide a
copy of the planning analyses results transmitted to the Nuclear Plant Generator
Operator, showing incorporation of the NPIRs. The Compliance Enforcement
Authority shall refer to the Agreements developed in accordance with this standard
for specific requirements.
R4.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall [Violation Risk Factor: High] [Time Horizon: Operations
Planning and Real-time Operations]
4.1. Incorporate the NPIRs into their operating analyses of the electric system.
4.2. Operate the electric system to meet the NPIRs.

Agreements may include mutually agreed upon procedures or protocols in effect between entities or between departments of
a vertically integrated system.

1

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NUC-001-4— Nuclear Plant Interface Coordination

4.3. Inform the Nuclear Plant Generator Operator when the ability to assess the
operation of the electric system affecting NPIRs is lost.
M4. Each Transmission Entity responsible for operating the electric system in accordance
with the Agreement shall demonstrate or provide evidence of the following, upon
request of the Compliance Enforcement Authority:

R5.

•

The NPIRs have been incorporated into the current operating analysis of the
electric system. (Requirement 4.1)

•

The electric system was operated to meet the NPIRs. (Requirement 4.2)

•

The Transmission Entity informed the Nuclear Plant Generator Operator when it
became aware it lost the capability to assess the operation of the electric system
affecting the NPIRs

Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall operate the nuclear plant to meet the NPIRs. [Violation Risk
Factor: High] [Time Horizon: Operations Planning and Real-time Operations ]

M5. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, demonstrate or provide evidence that the nuclear power
plant is being operated consistent with the NPIRs.
R6.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities and the Nuclear Plant Generator Operator shall coordinate
outages and maintenance activities which affect the NPIRs. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]

M6. The Transmission Entities and Nuclear Plant Generator Operator shall, upon request
of the Compliance Enforcement Authority, provide evidence of the coordination
between the Transmission Entities and the Nuclear Plant Generator Operator
regarding outages and maintenance activities which affect the NPIRs.
R7.

Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall inform the applicable Transmission Entities of actual or
proposed changes to nuclear plant design (e.g., protective relay setpoints),
configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]

M7. The Nuclear Plant Generator Operator shall provide evidence that it informed the
applicable Transmission Entities of changes to nuclear plant design (e.g., protective
relay setpoints), configuration, operations, limits, or capabilities that may impact the
ability of the Transmission Entities to meet the NPIRs.
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NUC-001-4— Nuclear Plant Interface Coordination

R8.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall inform the Nuclear Plant Generator Operator of actual or
proposed changes to electric system design (e.g., protective relay setpoints),
configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]

M8. The Transmission Entities shall each provide evidence that the entities informed the
Nuclear Plant Generator Operator of changes to electric system design (e.g.,
protective relay setpoints), configuration, operations, limits, or capabilities that may
impact the ability of the Nuclear Plant Generator Operator to meet the NPIRs.
R9.

The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
include the following elements in aggregate within the Agreement(s) identified in R2.
•

Where multiple Agreements with a single Transmission Entity are put into effect,
the R9 elements must be addressed in aggregate within the Agreements;
however, each Agreement does not have to contain each element. The Nuclear
Plant Generator Operator and the Transmission Entity are responsible for ensuring
all the R9 elements are addressed in aggregate within the Agreements.

•

Where Agreements with multiple Transmission Entities are required, the Nuclear
Plant Generator Operator is responsible for ensuring all the R9 elements are
addressed in aggregate within the Agreements with the Transmission Entities. The
Agreements with each Transmission Entity do not have to contain each element;
however, the Agreements with the multiple Transmission Entities, in the
aggregate, must address all R9 elements. For each Agreement(s), the Nuclear
Plant Generator Operator and the Transmission Entity are responsible to ensure
the Agreement(s) contain(s) the elements of R9 applicable to that Transmission
Entity. : [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

9.1. Retired. [Note: Part 9.1 was retired under the Paragraph 81 project. The NUC SDT
proposes to leave this Part blank to avoid renumbering Requirement parts that
would impact existing agreements throughout the industry.]
9.2. Technical requirements and analysis:
9.2.1. Identification of parameters, limits, configurations, and operating
scenarios included in the NPIRs and, as applicable, procedures for
providing any specific data not provided within the Agreement.
9.2.2. Identification of facilities, components, and configuration restrictions that
are essential for meeting the NPIRs.

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NUC-001-4— Nuclear Plant Interface Coordination

9.2.3. Types of planning and operational analyses performed specifically to
support the NPIRs, including the frequency of studies and types of
Contingencies and scenarios required.
9.3. Operations and maintenance coordination
9.3.1. Designation of ownership of electrical facilities at the interface between
the electric system and the nuclear plant and responsibilities for
operational control coordination and maintenance of these facilities.
9.3.2. Identification of any maintenance requirements for equipment not
owned or controlled by the Nuclear Plant Generator Operator that are
necessary to meet the NPIRs.
9.3.3. Coordination of testing, calibration and maintenance of on-site and offsite power supply systems and related components.
9.3.4. Provisions to address mitigating actions needed to avoid violating NPIRs
and to address periods when responsible Transmission Entity loses the
ability to assess the capability of the electric system to meet the NPIRs.
These provisions shall include responsibility to notify the Nuclear Plant
Generator Operator within a specified time frame.
9.3.5. Provision for considering, within the restoration process, the
requirements and urgency of a nuclear plant that has lost all off-site and
on-site AC power.
9.3.6. Coordination of physical and cyber security protection at the nuclear
plant interface to ensure each asset is covered under at least one entity’s
plan.
9.3.7. Coordination of the NPIRs with transmission system Remedial Action
Schemes and any programs that reduce or shed load based on
underfrequency or undervoltage.
9.4. Communications and training Administrative elements:
9.4.1. Provisions for communications affecting the NPIRs between the Nuclear
Plant Generator Operator and Transmission Entities, including
communications protocols, notification time requirements, and
definitions of applicable unique terms.
9.4.2. Provisions for coordination during an off-normal or emergency event
affecting the NPIRs, including the need to provide timely information
explaining the event, an estimate of when the system will be returned to
a normal state, and the actual time the system is returned to normal.
9.4.3. Provisions for coordinating investigations of causes of unplanned events
affecting the NPIRs and developing solutions to minimize future risk of
such events.

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NUC-001-4— Nuclear Plant Interface Coordination

9.4.4. Provisions for supplying information necessary to report to government
agencies, as related to NPIRs.
9.4.5. Provisions for personnel training, as related to NPIRs.
M9. The Nuclear Plant Generator Operator shall have a copy of the Agreement(s)
addressing the elements in Requirement 9 available for inspection upon request of the
Compliance Enforcement Authority. Each Transmission Entity shall have a copy of the
Agreement(s) addressing the elements in Requirement 9 for which it is responsible available
for inspection upon request of the Compliance Enforcement Authority.

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NUC-001-4— Nuclear Plant Interface Coordination

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints Text
1.3. Data Retention
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
•

For Measure 1, the Nuclear Plant Generator Operator shall keep its latest
transmittals and receipts.

•

For Measure 2, the Nuclear Plant Generator Operator and each
Transmission Entity shall have its current, in-force Agreement.

•

For Measure 3, the Transmission Entity shall have the latest planning
analysis results.

•

For Measures 4, 6 and 8, the Transmission Entity shall keep evidence for
two years plus current.

•

For Measures 5, 6 and 7, the Nuclear Plant Generator Operator shall keep
evidence for two years plus current.

If a Responsible Entity is found non-compliant it shall keep information related to
the noncompliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None

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NUC-001-4— Nuclear Plant Interface Coordination

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

R1

R2

Draft 1 of NUC-001-4
October 2019

Medium The Nuclear Plant
Generator Operator
provided the NPIRs to
the applicable entities
but did not verify
receipt.

Medium N/A

Moderate VSL

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIR to one
of the applicable
entities unless there
was only one entity.

N/A

High VSL

Severe VSL

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIRs to
two of the applicable
entities unless there
were only two
entities.

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIRs to
more than two of
applicable entities.

N/A

The Nuclear Plant
Generator Operator or
the applicable
Transmission Entity
does not have in effect
one or more
agreements that
include mutually
agreed to NPIRs and

OR
For a particular
nuclear power plant, if
the number of
possible applicable
transmission entities is
equal to the number
of applicable
transmission entities
not provided NPIRs

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

document the
implementation of the
NPIRs.
R3

Medium N/A

The responsible entity
incorporated the
NPIRs into its planning
analyses but did not
communicate the
results to the Nuclear
Plant Generator
Operator.

N/A

The responsible entity
did not incorporate
the NPIRs into its
planning analyses of
the electric system.

R4

High

N/A

The responsible entity
did not comply with
Requirement R4, Part
4.3.

The responsible entity
did not comply with
Requirement R4, Part
R4.1.

The responsible entity
did not comply with
Requirement R4, Part
R4.2.

R5

High

N/A

N/A

N/A

The Nuclear Plant
Generator Operator
failed to operate per
the NPIRs developed
in accordance with
this standard.

R6

Medium N/A

The Nuclear Plant
Generator Operator or
Transmission Entity
failed to provide

The Nuclear Plant
N/A
Generator Operator or
Transmission Entity
failed to coordinate

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

outage or
maintenance
schedules to the
appropriate parties as
described in the
agreement or on a
time period consistent
with the agreements.

High VSL

Severe VSL

one or more outages
or maintenance
activities in
accordance the
requirements of the
agreements.

R7

High

The Nuclear Plant
N/A
Generator Operator
did not inform the
applicable
Transmission Entities
of proposed changes
to nuclear plant design
(e.g. protective relay
setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

The Nuclear Plant
Generator Operator
did not inform the
applicable
Transmission Entities
of actual changes to
nuclear plant design
(e.g. protective relay
setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

The Nuclear Plant
Generator Operator
did not inform the
applicable
Transmission Entities
of actual changes to
nuclear plant design
(e.g., protective relay
setpoints),
configuration,
operations, limits or
capabilities that
directly impact the
ability of the electric
system to meet the
NPIRs.

R8

High

The applicable
Transmission Entities
did not inform the

The applicable
Transmission Entities
did not inform the

The applicable
Transmission Entities
did not inform the

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N/A

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

Nuclear Plant
Generator Operator of
proposed changes to
transmission system
design, configuration
(e.g. protective relay
setpoints), operations,
limits, or capabilities
that may impact the
ability of the electric
system to meet the
NPIRs.
R9

Draft 1 of NUC-001-4
October 2019

Medium

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include up to
20% of the combined
sub-components in
Requirement R9 Parts
9.2, 9.3 and 9.4
applicable to that
entity.

High VSL

Severe VSL

Nuclear Plant
Generator Operator of
actual changes to
transmission system
design (e.g. protective
relay setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

Nuclear Plant
Generator Operator of
actual changes to
transmission system
design (e.g. protective
relay setpoints),
configuration,
operations, limits, or
capabilities that
directly impacts the
ability of the electric
system to meet the
NPIRs.

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include
greater than 20%, but
less than 40% of the
combined subcomponents in
Requirement R9 Parts
9.2, 9.3 and 9.4

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include 40%
or more of the
combined subcomponents in
Requirement R9 Parts
9.2, 9.3 and 9.4

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

applicable to the
entity.

Draft 1 of NUC-001-4
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Severe VSL

applicable to the
entity.

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NUC-001-4— Nuclear Plant Interface Coordination

D. Regional Variances
The design basis for Canadian (CANDU) nuclear power plants (NPPs) does not result in the
same licensing requirements as U.S. NPPs. Nuclear Regulatory Commission (NRC) design
criteria specifies that in addition to emergency on-site electrical power, electrical power
from the electric network also be provided to permit safe shutdown. There are no
equivalent Canadian Regulatory requirements for electrical power from the electric network
to be provided to permit safe shutdown. Therefore the definition of Nuclear Plant Licensing
Requirements (NPLR) for Canadian CANDU NPPs will be as follows:
Canadian Nuclear Plant Licensing Requirements (CNPLR) are requirements included in the
design basis of the nuclear plant and are statutorily mandated for the operation of the
plant; when used in this standard, NPLR shall mean nuclear power plant licensing
requirements for avoiding preventable challenges to nuclear safety as a result of an electric
system disturbance, transient, or condition.

E. Interpretations
None

F. Associated Documents
None

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NUC-001-4— Nuclear Plant Interface Coordination

Version History
Version

Date

Action

Change Tracking

1

May 2, 2007

Approved by Board of
Trustees

2

August 5, 2009

Adopted by Board of Trustees Revised. Modifications
for Order 716 to
Requirement R9.3.5 and
footnote 1;
modifications to bring
compliance elements
into conformance with
the latest version of the
ERO Rules of Procedure.

2

January 22, 2010

Approved by FERC on January
21, 2010. Added Effective
Date

2

February 7, 2013

R9.1, R9.1.1, R9.1.2, R9.1.3,
and R9.1.4 and associated
elements approved by NERC
Board of Trustees for
retirement as part of the
Paragraph 81 project (Project
2013-02) pending applicable
regulatory approval.

2

November 21, 2013 R9.1, R9.1.1, R9.1.2, R9.1.3,
and R9.1.4 and associated
elements approved by FERC
for retirement as part of the
Paragraph 81 project (Project
2013-02)

2.1

April 11, 2012

2.1

September 9, 2013

Draft 1 of NUC-001-4
October 2019

New

Update

Errata approved by the
Errata associated with
Standards Committee;
Project 2007-17
(Capitalized “Protection
System” in accordance with
Implementation Plan for
Project 2007-17 approval of
revised definition of
“Protection System”)
Informational filing submitted
to reflect the revised

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NUC-001-4— Nuclear Plant Interface Coordination

definition of Protection
System in accordance with
the Implementation Plan for
the revised term.
3

March 2014

Modifications to implement
the recommendations of the
five-year review of NUC-001,
which was accepted by the
Standards Committee on
October 17, 2013.

3

August 14, 2014

Adopted by the NERC Board
of Trustees

3

November 4, 2014

FERC letter order issued
approving NUC-001-3

4

Revision

Adopted by the NERC Board
of Trustees

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 R5:
The NUC FYRT recommended R5 be revised for consistency with R4 and to clarify that nuclear
plants must be operated to meet the Nuclear Plant Interface Requirements.
Rationale for R7 and R8:
The NUC FYRT recommended deleting “Protection Systems” in Requirements R7 and R8 since it
is a subset of the "nuclear plant design" and "electric system design" elements currently
contained in R7 and R8 respectively; and adding a parenthetical clause (e.g. protective
setpoints) to R7 following "nuclear plant design" and parenthetical clause (e.g. relay setpoints)
to R8 following "electric system design."
Rationale for R9:
The NUC FYRT recommended that R9 be revised to clarify that all agreements do not have to
discuss each of the elements in R9, but that the sum total of the agreements need to address
the elements. In addition, for clarity in Part 9.4.1, the NUC FYRT recommended that "affecting
the NPIRs" be inserted following "Provisions for communications" and "applicable unique" be
inserted following ""definitions of."

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NUC-001-4— Nuclear Plant Interface Coordination

Rationale for R9.3.7:
The term “Special Protection Systems” (SPS) was replaced with “Remedial Action Schemes”
(RAS) in order to align with other current NERC standards development work in Project 201005.2: Special Protection Systems. Project 2010-05.2 has proposed to replace SPS with RAS
throughout all of the NERC Standards in order to move to the use of a single term. RAS and SPS
have the same definition in the NERC Glossary of Terms.

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NUC-001-34— Nuclear Plant Interface Coordination

A. Introduction
1.

Title:

Nuclear Plant Interface Coordination

2.

Number:

NUC-001-43

3.

Purpose: This standard requires coordination between Nuclear Plant Generator
Operators and Transmission Entities for the purpose of ensuring nuclear plant safe
operation and shutdown.

4.

Applicability:
4.1. Functional Entities:
4.1.1

Nuclear Plant Generator Operators.

4.2. Transmission Entities shall mean all entities that are responsible for providing
services related to Nuclear Plant Interface Requirements (NPIRs). Such entities
may include one or more of the following:

5.

4.2.1

Transmission Operators.

4.2.2

Transmission Owners.

4.2.3

Transmission Planners.

4.2.4

Transmission Service Providers.

4.2.5

Balancing Authorities.

4.2.6

Reliability Coordinators.

4.2.7

Planning Coordinators.

4.2.8

Distribution Providers.

4.2.9

Load-Serving Entities.

4.2.104.2.9

Generator Owners.

4.2.114.2.10

Generator Operators.

Background: Project 2012-13 Nuclear Power Interface Coordination seeks to
implement the changes that were proposed by the NUC FYRT. The NUC FYRT was
appointed by the Standards Committee Executive Committee on April 22, 2013. The
NUC FYRT reviewed the NUC-001-2.1 standard to identify opportunities for
consolidation and additional improvements. The NUC FYRT posted its
recommendation to revise NUC-001-2.1 for industry comment on July 27, 2013. The
NUC FYRT considered comments and submitted its final recommendation to revise
NUC-001-2.1, along with a Standards Authorization Request (SAR) to the Standards
Committee on October 17, 2013. The Standards Committee accepted the

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NUC-001-34— Nuclear Plant Interface Coordination

recommendation of the FYRT and appointed the team as the Standard Drafting Team
(SDT) to implement the recommendation.
6.

Effective Dates: First day of the first calendar quarter that is twelve months beyond
the date that this standard is approved by applicable regulatory authorities, 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 that is twelve months after the date this standard is
adopted by the NERC Board of Trustees or as otherwise provided for in that
jurisdiction.

B. Requirements and Measures
R1. The Nuclear Plant Generator Operator shall provide the proposed NPIRs in writing to
the applicable Transmission Entities and shall verify receipt. [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning ]
M1. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, provide a copy of the transmittal and receipt of transmittal of
the proposed NPIRs to the responsible Transmission Entities.
R2. The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
have in effect one or more Agreements 1 that include mutually agreed to NPIRs and
document how the Nuclear Plant Generator Operator and the applicable Transmission
Entities shall address and implement these NPIRs. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning ]
M2. The Nuclear Plant Generator Operator and each Transmission Entity shall each have a
copy of the currently effective Agreement(s) which document how the Nuclear Plant
Generator Operator and the applicable Transmission Entities address and implement
the NPIRs available for inspection upon request of the Compliance Enforcement
Authority.
R3. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall incorporate the NPIRs into their planning analyses of the
electric system and shall communicate the results of these analyses to the Nuclear Plant
Generator Operator.: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning ]
M3. Each Transmission Entity responsible for planning analyses in accordance with the
Agreement shall, upon request of the Compliance Enforcement Authority, provide a
copy of the planning analyses results transmitted to the Nuclear Plant Generator
Operator, showing incorporation of the NPIRs. The Compliance Enforcement
1

Agreements may include mutually agreed upon procedures or protocols in effect between entities or between
departments of a vertically integrated system.

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NUC-001-34— Nuclear Plant Interface Coordination

Authority shall refer to the Agreements developed in accordance with this standard for
specific requirements.
R4. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall [Violation Risk Factor: High] [Time Horizon: Operations
Planning and Real-time Operations]
4.1. Incorporate the NPIRs into their operating analyses of the electric system.
4.2. Operate the electric system to meet the NPIRs.
4.3. Inform the Nuclear Plant Generator Operator when the ability to assess the
operation of the electric system affecting NPIRs is lost.
M4. Each Transmission Entity responsible for operating the electric system in accordance
with the Agreement shall demonstrate or provide evidence of the following, upon
request of the Compliance Enforcement Authority:
•

The NPIRs have been incorporated into the current operating analysis of the
electric system. (Requirement 4.1)

•

The electric system was operated to meet the NPIRs. (Requirement 4.2)

•

The Transmission Entity informed the Nuclear Plant Generator Operator when
it became aware it lost the capability to assess the operation of the electric
system affecting the NPIRs

R5. Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall operate the nuclear plant to meet the NPIRs. [Violation Risk
Factor: High] [Time Horizon: Operations Planning and Real-time Operations ]
M5. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, demonstrate or provide evidence that the nuclear power plant
is being operated consistent with the NPIRs.
R6. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities and the Nuclear Plant Generator Operator shall coordinate
outages and maintenance activities which affect the NPIRs. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]
M6. The Transmission Entities and Nuclear Plant Generator Operator shall, upon request of
the Compliance Enforcement Authority, provide evidence of the coordination between
the Transmission Entities and the Nuclear Plant Generator Operator regarding outages
and maintenance activities which affect the NPIRs.
R7. Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall inform the applicable Transmission Entities of actual or
proposed changes to nuclear plant design (e.g., protective relay setpoints),

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NUC-001-34— Nuclear Plant Interface Coordination

configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
M7. The Nuclear Plant Generator Operator shall provide evidence that it informed the
applicable Transmission Entities of changes to nuclear plant design (e.g., protective
relay setpoints), configuration, operations, limits, or capabilities that may impact the
ability of the Transmission Entities to meet the NPIRs.
R8. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall inform the Nuclear Plant Generator Operator of actual or
proposed changes to electric system design (e.g., protective relay setpoints),
configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
M8. The Transmission Entities shall each provide evidence that the entities informed the
Nuclear Plant Generator Operator of changes to electric system design (e.g., protective
relay setpoints), configuration, operations, limits, or capabilities that may impact the
ability of the Nuclear Plant Generator Operator to meet the NPIRs.
R9. The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
include the following elements in aggregate within the Agreement(s) identified in R2.
•

Where multiple Agreements with a single Transmission Entity are put into
effect, the R9 elements must be addressed in aggregate within the
Agreements; however, each Agreement does not have to contain each
element. The Nuclear Plant Generator Operator and the Transmission Entity
are responsible for ensuring all the R9 elements are addressed in aggregate
within the Agreements.

•

Where Agreements with multiple Transmission Entities are required, the
Nuclear Plant Generator Operator is responsible for ensuring all the R9
elements are addressed in aggregate within the Agreements with the
Transmission Entities. The Agreements with each Transmission Entity do not
have to contain each element; however, the Agreements with the multiple
Transmission Entities, in the aggregate, must address all R9 elements. For
each Agreement(s), the Nuclear Plant Generator Operator and the
Transmission Entity are responsible to ensure the Agreement(s) contain(s) the
elements of R9 applicable to that Transmission Entity. : [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]

9.1. Retired. [Note: Part 9.1 was retired under the Paragraph 81 project. The NUC
SDT proposes to leave this Part blank to avoid renumbering Requirement parts
that would impact existing agreements throughout the industry.]

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NUC-001-34— Nuclear Plant Interface Coordination

9.2. Technical requirements and analysis:
9.2.1. Identification of parameters, limits, configurations, and operating
scenarios included in the NPIRs and, as applicable, procedures for
providing any specific data not provided within the Agreement.
9.2.2. Identification of facilities, components, and configuration restrictions that
are essential for meeting the NPIRs.
9.2.3. Types of planning and operational analyses performed specifically to
support the NPIRs, including the frequency of studies and types of
Contingencies and scenarios required.
9.3. Operations and maintenance coordination
9.3.1. Designation of ownership of electrical facilities at the interface between
the electric system and the nuclear plant and responsibilities for
operational control coordination and maintenance of these facilities.
9.3.2. Identification of any maintenance requirements for equipment not owned
or controlled by the Nuclear Plant Generator Operator that are necessary
to meet the NPIRs.
9.3.3. Coordination of testing, calibration and maintenance of on-site and off-site
power supply systems and related components.
9.3.4. Provisions to address mitigating actions needed to avoid violating NPIRs
and to address periods when responsible Transmission Entity loses the
ability to assess the capability of the electric system to meet the NPIRs.
These provisions shall include responsibility to notify the Nuclear Plant
Generator Operator within a specified time frame.
9.3.5. Provision for considering, within the restoration process, the requirements
and urgency of a nuclear plant that has lost all off-site and on-site AC
power.
9.3.6. Coordination of physical and cyber security protection at the nuclear plant
interface to ensure each asset is covered under at least one entity’s plan.
9.3.7. Coordination of the NPIRs with transmission system Remedial Action
Schemes and any programs that reduce or shed load based on
underfrequency or undervoltage.
9.4. Communications and training Administrative elements:
9.4.1. Provisions for communications affecting the NPIRs between the Nuclear
Plant Generator Operator and Transmission Entities, including
communications protocols, notification time requirements, and definitions
of applicable unique terms.
9.4.2. Provisions for coordination during an off-normal or emergency event
affecting the NPIRs, including the need to provide timely information
explaining the event, an estimate of when the system will be returned to a
normal state, and the actual time the system is returned to normal.

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NUC-001-34— Nuclear Plant Interface Coordination

9.4.3. Provisions for coordinating investigations of causes of unplanned events
affecting the NPIRs and developing solutions to minimize future risk of
such events.
9.4.4. Provisions for supplying information necessary to report to government
agencies, as related to NPIRs.
9.4.5. Provisions for personnel training, as related to NPIRs.
M9. The Nuclear Plant Generator Operator shall have a copy of the Agreement(s) addressing
the elements in Requirement 9 available for inspection upon request of the Compliance
Enforcement Authority. Each Transmission Entity shall have a copy of the Agreement(s)
addressing the elements in Requirement 9 for which it is responsible available for inspection
upon request of the Compliance Enforcement Authority.

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints Text
1.3. Data Retention
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
•

For Measure 1, the Nuclear Plant Generator Operator shall keep its latest
transmittals and receipts.

•

For Measure 2, the Nuclear Plant Generator Operator and each
Transmission Entity shall have its current, in-force Agreement.

•

For Measure 3, the Transmission Entity shall have the latest planning
analysis results.

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NUC-001-34— Nuclear Plant Interface Coordination

•

For Measures 4, 6 and 8, the Transmission Entity shall keep evidence for
two years plus current.

•

For Measures 5, 6 and 7, the Nuclear Plant Generator Operator shall keep
evidence for two years plus current.

If a Responsible Entity is found non-compliant it shall keep information related to
the noncompliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None

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NUC-001-34— Nuclear Plant Interface Coordination

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

R1

Medium The Nuclear Plant
Generator Operator
provided the NPIRs to the
applicable entities but did
not verify receipt.

Moderate VSL

High VSL

Severe VSL

The Nuclear Plant
Generator Operator did not
provide the proposed NPIR
to one of the applicable
entities unless there was
only one entity.

The Nuclear Plant
Generator Operator did not
provide the proposed
NPIRs to two of the
applicable entities unless
there were only two
entities.

The Nuclear Plant
Generator Operator did not
provide the proposed
NPIRs to more than two of
applicable entities.
OR
For a particular nuclear
power plant, if the number
of possible applicable
transmission entities is
equal to the number of
applicable transmission
entities not provided NPIRs

R2

Medium N/A

N/A

N/A

The Nuclear Plant
Generator Operator or the
applicable Transmission
Entity does not have in
effect one or more
agreements that include
mutually agreed to NPIRs
and document the
implementation of the
NPIRs.

R3

Medium N/A

The responsible entity
incorporated the NPIRs
into its planning analyses
but did not communicate

N/A

The responsible entity did
not incorporate the NPIRs
into its planning analyses of
the electric system.

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NUC-001-34— Nuclear Plant Interface Coordination
the results to the Nuclear
Plant Generator Operator.

R4

High

N/A

The responsible entity did
not comply with
Requirement R4, Part 4.3.

The responsible entity did
not comply with
Requirement R4, Part R4.1.

The responsible entity did
not comply with
Requirement R4, Part R4.2.

R5

High

N/A

N/A

N/A

The Nuclear Plant
Generator Operator failed
to operate per the NPIRs
developed in accordance
with this standard.

R6

Medium N/A

The Nuclear Plant
Generator Operator or
Transmission Entity failed
to provide outage or
maintenance schedules to
the appropriate parties as
described in the agreement
or on a time period
consistent with the
agreements.

The Nuclear Plant
Generator Operator or
Transmission Entity failed
to coordinate one or more
outages or maintenance
activities in accordance the
requirements of the
agreements.

N/A

R7

High

The Nuclear Plant
Generator Operator did not
inform the applicable
Transmission Entities
of proposed changes to
nuclear plant design (e.g.
protective relay setpoints),
configuration, operations,
limits, or capabilities that
may impact the ability of
the electric system to meet
the NPIRs.

N/A

The Nuclear Plant
Generator Operator did not
inform the applicable
Transmission Entities
of actual changes to nuclear
plant design (e.g. protective
relay setpoints),
configuration, operations,
limits, or capabilities
that may impact the ability
of the electric system to
meet the NPIRs.

The Nuclear Plant
Generator Operator did not
inform the applicable
Transmission Entities
of actual changes to nuclear
plant design (e.g.,
protective relay setpoints),
configuration, operations,
limits or capabilities
that directly impact the
ability of the electric
system to meet the NPIRs.

R8

High

The applicable
Transmission Entities did
not inform the Nuclear

N/A

The applicable
Transmission Entities did
not inform the Nuclear

The applicable
Transmission Entities did
not inform the Nuclear

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NUC-001-34— Nuclear Plant Interface Coordination
Plant Generator Operator
of proposed changes to
transmission system design,
configuration (e.g.
protective relay setpoints),
operations, limits, or
capabilities that may
impact the ability of the
electric system to meet the
NPIRs.

R9

Medium

The Agreement(s)
identified in R2. between
the Nuclear Plant Generator
Operator and the applicable
Transmission Entity failed
to include up to 20% of the
combined sub-components
in Requirement R9 Parts
9.2, 9.3 and 9.4 applicable
to that entity.

Plant Generator Operator
of actual changes to
transmission system design
(e.g. protective relay
setpoints), configuration,
operations, limits, or
capabilities that may
impact the ability of the
electric system to meet the
NPIRs.

Plant Generator Operator
of actual changes to
transmission system design
(e.g. protective relay
setpoints), configuration,
operations, limits, or
capabilities that directly
impacts the ability of the
electric system to meet the
NPIRs.

The Agreement(s)
identified in R2. between
the Nuclear Plant Generator
Operator and the applicable
Transmission Entity failed
to include greater than
20%, but less than 40% of
the combined subcomponents in
Requirement R9 Parts 9.2,
9.3 and 9.4 applicable to
the entity.

The Agreement(s)
identified in R2. between
the Nuclear Plant Generator
Operator and the applicable
Transmission Entity failed
to include 40% or more of
the combined subcomponents in
Requirement R9 Parts 9.2,
9.3 and 9.4 applicable to
the entity.

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NUC-001-4— Nuclear Plant Interface Coordination

D. Regional Variances
The design basis for Canadian (CANDU) nuclear power plants (NPPs) does not result in the
same licensing requirements as U.S. NPPs. Nuclear Regulatory Commission (NRC) design
criteria specifies that in addition to emergency on-site electrical power, electrical power from
the electric network also be provided to permit safe shutdown. There are no equivalent
Canadian Regulatory requirements for electrical power from the electric network to be
provided to permit safe shutdown. Therefore the definition of Nuclear Plant Licensing
Requirements (NPLR) for Canadian CANDU NPPs will be as follows:
Canadian Nuclear Plant Licensing Requirements (CNPLR) are requirements included in the
design basis of the nuclear plant and are statutorily mandated for the operation of the plant;
when used in this standard, NPLR shall mean nuclear power plant licensing requirements for
avoiding preventable challenges to nuclear safety as a result of an electric system
disturbance, transient, or condition.
E. Interpretations
None.
F. Associated Documents
None

Version History

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NUC-001-4— Nuclear Plant Interface Coordination

Version

Date

Action

Change Tracking

1

May 2, 2007

Approved by Board of Trustees

New

2

August 5, 2009

Adopted by Board of Trustees

Revised. Modifications for
Order 716 to Requirement
R9.3.5 and footnote 1;
modifications to bring
compliance elements into
conformance with the
latest version of the ERO
Rules of Procedure.

2

January 22, 2010

Approved by FERC on January 21,
2010. Added Effective Date

Update

2

February 7, 2013

R9.1, R9.1.1, R9.1.2, R9.1.3, and
R9.1.4 and associated elements
approved by NERC Board of
Trustees for retirement as part of the
Paragraph 81 project (Project 201302) pending applicable regulatory
approval.

2

November 21,
2013

2.1

April 11, 2012

2.1

September 9,
2013

3

March 2014

R9.1, R9.1.1, R9.1.2, R9.1.3, and
R9.1.4 and associated elements
approved by FERC for retirement as
part of the Paragraph 81 project
(Project 2013-02)
Errata approved by the Standards
Committee; (Capitalized “Protection
System” in accordance with
Implementation Plan for Project
2007-17 approval of revised
definition of “Protection System”)
Informational filing submitted to
reflect the revised definition of
Protection System in accordance
with the Implementation Plan for the
revised term.
Modifications to implement the
recommendations of the five-year
review of NUC-001, which was
accepted by the Standards
Committee on October 17, 2013.

3

August 14, 2014

Adopted by the NERC Board of
Trustees

3

November 4,
2014

FERC letter order issued approving
NUC-001-3

Errata associated with
Project 2007-17

Revision

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NUC-001-4— Nuclear Plant Interface Coordination

4

Adopted by the NERC Board of
Trustees

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 R5:
The NUC FYRT recommended R5 be revised for consistency with R4 and to clarify that nuclear
plants must be operated to meet the Nuclear Plant Interface Requirements.
Rationale for R7 and R8:
The NUC FYRT recommended deleting “Protection Systems” in Requirements R7 and R8 since
it is a subset of the "nuclear plant design" and "electric system design" elements currently
contained in R7 and R8 respectively; and adding a parenthetical clause (e.g. protective setpoints)
to R7 following "nuclear plant design" and parenthetical clause (e.g. relay setpoints) to R8
following "electric system design."

Rationale for R9:
The NUC FYRT recommended that R9 be revised to clarify that all agreements do not have to
discuss each of the elements in R9, but that the sum total of the agreements need to address the
elements. In addition, for clarity in Part 9.4.1, the NUC FYRT recommended that "affecting the
NPIRs" be inserted following "Provisions for communications" and "applicable unique" be
inserted following ""definitions of."
Rationale for R9.3.7:
The term “Special Protection Systems” (SPS) was replaced with “Remedial Action Schemes”
(RAS) in order to align with other current NERC standards development work in Project 201005.2: Special Protection Systems. Project 2010-05.2 has proposed to replace SPS with RAS
throughout all of the NERC Standards in order to move to the use of a single term. RAS and SPS
have the same definition in the NERC Glossary of Terms.

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PRC-006-4 — Automatic Underfrequency Load Shedding

A. Introduction
1.
Title:
Automatic Underfrequency Load Shedding
2.

Number:

3.

Purpose: To establish design and documentation requirements for automatic
underfrequency load shedding (UFLS) programs to arrest declining frequency, assist
recovery of frequency following underfrequency events and provide last resort
system preservation measures.

4.

Applicability:

PRC-006-4

4.1. Planning Coordinators
4.2. UFLS entities shall mean all entities that are responsible for the ownership,
operation, or control of UFLS equipment as required by the UFLS program
established by the Planning Coordinators. Such entities may include one or
more of the following:
4.2.1 Transmission Owners
4.2.2 Distribution Providers
4.2.3 UFLS-Only Distribution Providers 1
4.3. Transmission Owners that own Elements identified in the UFLS program
established by the Planning Coordinators.
5.

Effective Date:
See Implementation Plan

B. Requirements and Measures
R1.

Each Planning Coordinator shall develop and document criteria, including
consideration of historical events and system studies, to select portions of the Bulk
Electric System (BES), including interconnected portions of the BES in adjacent
Planning Coordinator areas and Regional Entity areas that may form islands. [VRF:
Medium][Time Horizon: Long-term Planning]

M1. Each Planning Coordinator shall have evidence such as reports, or other documentation
of its criteria to select portions of the Bulk Electric System that may form islands
including how system studies and historical events were considered to develop the
criteria per Requirement R1.
R2.

Each Planning Coordinator shall identify one or more islands to serve as a basis for
designing its UFLS program including: [VRF: Medium][Time Horizon: Long-term
Planning]

NERC Rules of Procedure, Appendix 5
https://www.nerc.com/FilingsOrders/us/RuleOfProcedureDL/NERC_ROP_Effective_20160504.pdf

1

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PRC-006-4 — Automatic Underfrequency Load Shedding

2.1. Those islands selected by applying the criteria in Requirement R1, and
2.2. Any portions of the BES designed to detach from the Interconnection (planned
islands) as a result of the operation of a relay scheme or Special Protection
System, and
2.3. A single island that includes all portions of the BES in either the Regional Entity
area or the Interconnection in which the Planning Coordinator’s area resides. If a
Planning Coordinator’s area resides in multiple Regional Entity areas, each of
those Regional Entity areas shall be identified as an island. Planning Coordinators
may adjust island boundaries to differ from Regional Entity area boundaries by
mutual consent where necessary for the sole purpose of producing contiguous
regional islands more suitable for simulation.
M2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s) as a basis
for designing a UFLS program that meet the criteria in Requirement R2, Parts 2.1
through 2.3.
R3.

Each Planning Coordinator shall develop a UFLS program, including notification of and
a schedule for implementation by UFLS entities within its area, that meets the
following performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s). [VRF:
High][Time Horizon: Long-term Planning]
3.1. Frequency shall remain above the Underfrequency Performance Characteristic
curve in PRC-006-3 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
3.2. Frequency shall remain below the Overfrequency Performance Characteristic
curve in PRC-006-3 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
3.3. Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two seconds
cumulatively per simulated event, and shall not exceed 1.10 per unit for longer
than 45 seconds cumulatively per simulated event at each generator bus and
generator step-up transformer high-side bus associated with each of the
following:
• Individual generating units greater than 20 MVA (gross nameplate rating)
directly connected to the BES
• Generating plants/facilities greater than 75 MVA (gross aggregate nameplate
rating) directly connected to the BES
• Facilities consisting of one or more units connected to the BES at a common
bus with total generation above 75 MVA gross nameplate rating.

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PRC-006-4 — Automatic Underfrequency Load Shedding

M3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its UFLS program, including the
notification of the UFLS entities of implementation schedule, that meet the criteria in
Requirement R3, Parts 3.1 through 3.3.
R4.

Each Planning Coordinator shall conduct and document a UFLS design assessment at
least once every five years that determines through dynamic simulation whether the
UFLS program design meets the performance characteristics in Requirement R3 for
each island identified in Requirement R2. The simulation shall model each of the
following: [VRF: High][Time Horizon: Long-term Planning]
4.1. Underfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip above the
Generator Underfrequency Trip Modeling curve in PRC-006-3 - Attachment 1.
4.2. Underfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip above
the Generator Underfrequency Trip Modeling curve in PRC-006-3 - Attachment 1.
4.3. Underfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-3 - Attachment 1.
4.4. Overfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-3 — Attachment 1.
4.5. Overfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip below
the Generator Overfrequency Trip Modeling curve in PRC-006-3 — Attachment 1.
4.6. Overfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-3 — Attachment 1.
4.7. Any automatic Load restoration that impacts frequency stabilization and operates
within the duration of the simulations run for the assessment.

M4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its UFLS design
assessment that demonstrates it meets Requirement R4, Parts 4.1 through 4.7.
R5.

Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall coordinate its UFLS program design
with all other Planning Coordinators whose areas or portions of whose areas are also

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PRC-006-4 — Automatic Underfrequency Load Shedding

part of the same identified island through one of the following: [VRF: High][Time
Horizon: Long-term Planning]
•

Develop a common UFLS program design and schedule for implementation per
Requirement R3 among the Planning Coordinators whose areas or portions of
whose areas are part of the same identified island, or

•

Conduct a joint UFLS design assessment per Requirement R4 among the Planning
Coordinators whose areas or portions of whose areas are part of the same
identified island, or

•

Conduct an independent UFLS design assessment per Requirement R4 for the
identified island, and in the event the UFLS design assessment fails to meet
Requirement R3, identify modifications to the UFLS program(s) to meet
Requirement R3 and report these modifications as recommendations to the other
Planning Coordinators whose areas or portions of whose areas are also part of
the same identified island and the ERO.

M5. Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall have dated evidence such as joint
UFLS program design documents, reports describing a joint UFLS design assessment,
letters that include recommendations, or other dated documentation demonstrating
that it coordinated its UFLS program design with all other Planning Coordinators whose
areas or portions of whose areas are also part of the same identified island per
Requirement R5.
R6.

Each Planning Coordinator shall maintain a UFLS database containing data necessary to
model its UFLS program for use in event analyses and assessments of the UFLS
program at least once each calendar year, with no more than 15 months between
maintenance activities. [VRF: Lower][Time Horizon: Long-term Planning]

M6. Each Planning Coordinator shall have dated evidence such as a UFLS database, data
requests, data input forms, or other dated documentation to show that it maintained a
UFLS database for use in event analyses and assessments of the UFLS program per
Requirement R6 at least once each calendar year, with no more than 15 months
between maintenance activities.
R7.

Each Planning Coordinator shall provide its UFLS database containing data necessary to
model its UFLS program to other Planning Coordinators within its Interconnection
within 30 calendar days of a request. [VRF: Lower][Time Horizon: Long-term Planning]

M7. Each Planning Coordinator shall have dated evidence such as letters, memorandums,
e-mails or other dated documentation that it provided their UFLS database to other
Planning Coordinators within their Interconnection within 30 calendar days of a
request per Requirement R7.
R8.

Each UFLS entity shall provide data to its Planning Coordinator(s) according to the
format and schedule specified by the Planning Coordinator(s) to support maintenance

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PRC-006-4 — Automatic Underfrequency Load Shedding

of each Planning Coordinator’s UFLS database. [VRF: Lower][Time Horizon: Long-term
Planning]
M8. Each UFLS Entity shall have dated evidence such as responses to data requests,
spreadsheets, letters or other dated documentation that it provided data to its
Planning Coordinator according to the format and schedule specified by the Planning
Coordinator to support maintenance of the UFLS database per Requirement R8.
R9.

Each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
as determined by its Planning Coordinator(s) in each Planning Coordinator area in
which it owns assets. [VRF: High][Time Horizon: Long-term Planning]

M9. Each UFLS Entity shall have dated evidence such as spreadsheets summarizing feeder
load armed with UFLS relays, spreadsheets with UFLS relay settings, or other dated
documentation that it provided automatic tripping of load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
per Requirement R9.
R10. Each Transmission Owner shall provide automatic switching of its existing capacitor
banks, Transmission Lines, and reactors to control over-voltage as a result of
underfrequency load shedding if required by the UFLS program and schedule for
implementation, including any Corrective Action Plan, as determined by the Planning
Coordinator(s) in each Planning Coordinator area in which the Transmission Owner
owns transmission. [VRF: High][Time Horizon: Long-term Planning]
M10. Each Transmission Owner shall have dated evidence such as relay settings, tripping
logic or other dated documentation that it provided automatic switching of its existing
capacitor banks, Transmission Lines, and reactors in order to control over-voltage as a
result of underfrequency load shedding if required by the UFLS program and schedule
for implementation, including any Corrective Action Plan, per Requirement R10.
R11. Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
conduct and document an assessment of the event within one year of event actuation
to evaluate: [VRF: Medium][Time Horizon: Operations Assessment]
11.1. The performance of the UFLS equipment,
11.2. The effectiveness of the UFLS program.
M11. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted an
event assessment of the performance of the UFLS equipment and the effectiveness of
the UFLS program per Requirement R11.
R12. Each Planning Coordinator, in whose islanding event assessment (per R11) UFLS
program deficiencies are identified, shall conduct and document a UFLS design

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PRC-006-4 — Automatic Underfrequency Load Shedding

assessment to consider the identified deficiencies within two years of event actuation.
[VRF: Medium][Time Horizon: Operations Assessment]
M12. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted a
UFLS design assessment per Requirements R12 and R4 if UFLS program deficiencies are
identified in R11.
R13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall coordinate its event assessment (in accordance
with Requirement R11) with all other Planning Coordinators whose areas or portions of
whose areas were also included in the same islanding event through one of the
following: [VRF: Medium][Time Horizon: Operations Assessment]
•

Conduct a joint event assessment per Requirement R11 among the Planning
Coordinators whose areas or portions of whose areas were included in the same
islanding event, or

•

Conduct an independent event assessment per Requirement R11 that reaches
conclusions and recommendations consistent with those of the event
assessments of the other Planning Coordinators whose areas or portions of
whose areas were included in the same islanding event, or

•

Conduct an independent event assessment per Requirement R11 and where the
assessment fails to reach conclusions and recommendations consistent with
those of the event assessments of the other Planning Coordinators whose areas
or portions of whose areas were included in the same islanding event, identify
differences in the assessments that likely resulted in the differences in the
conclusions and recommendations and report these differences to the other
Planning Coordinators whose areas or portions of whose areas were included in
the same islanding event and the ERO.

M13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall have dated evidence such as a joint assessment
report, independent assessment reports and letters describing likely reasons for
differences in conclusions and recommendations, or other dated documentation
demonstrating it coordinated its event assessment (per Requirement R11) with all
other Planning Coordinator(s) whose areas or portions of whose areas were also
included in the same islanding event per Requirement R13.
R14. Each Planning Coordinator shall respond to written comments submitted by UFLS
entities and Transmission Owners within its Planning Coordinator area following a
comment period and before finalizing its UFLS program, indicating in the written
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PRC-006-4 — Automatic Underfrequency Load Shedding

response to comments whether changes will be made or reasons why changes will not
be made to the following [VRF: Lower][Time Horizon: Long-term Planning]:
14.1. UFLS program, including a schedule for implementation
14.2. UFLS design assessment
14.3. Format and schedule of UFLS data submittal
M14. Each Planning Coordinator shall have dated evidence of responses, such as e-mails and
letters, to written comments submitted by UFLS entities and Transmission Owners
within its Planning Coordinator area following a comment period and before finalizing
its UFLS program per Requirement R14.
R15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall develop a Corrective Action Plan
and a schedule for implementation by the UFLS entities within its area. [VRF:
High][Time Horizon: Long-term Planning]
15.1. For UFLS design assessments performed under Requirement R4 or R5, the
Corrective Action Plan shall be developed within the five-year time frame
identified in Requirement R4.
15.2. For UFLS design assessments performed under Requirement R12, the Corrective
Action Plan shall be developed within the two-year time frame identified in
Requirement R12.
M15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall have a dated Corrective Action
Plan and a schedule for implementation by the UFLS entities within its area, that was
developed within the time frame identified in Part 15.1 or 15.2.

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C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
Each Planning Coordinator and UFLS entity shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
•

Each Planning Coordinator shall retain the current evidence of Requirements
R1, R2, R3, R4, R5, R12, R14, and R15, Measures M1, M2, M3, M4, M5, M12,
M14, and M15 as well as any evidence necessary to show compliance since
the last compliance audit.

•

Each Planning Coordinator shall retain the current evidence of UFLS database
update in accordance with Requirement R6, Measure M6, and evidence of the
prior year’s UFLS database update.

•

Each Planning Coordinator shall retain evidence of any UFLS database
transmittal to another Planning Coordinator since the last compliance audit in
accordance with Requirement R7, Measure M7.

•

Each UFLS entity shall retain evidence of UFLS data transmittal to the Planning
Coordinator(s) since the last compliance audit in accordance with
Requirement R8, Measure M8.

•

Each UFLS entity shall retain the current evidence of adherence with the UFLS
program in accordance with Requirement R9, Measure M9, and evidence of
adherence since the last compliance audit.

•

Transmission Owner shall retain the current evidence of adherence with the
UFLS program in accordance with Requirement R10, Measure M10, and
evidence of adherence since the last compliance audit.

•

Each Planning Coordinator shall retain evidence of Requirements R11, and
R13, and Measures M11, and M13 for 6 calendar years.

If a Planning Coordinator or UFLS entity is found non-compliant, it shall keep
information related to the non-compliance until found compliant or for the
retention period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
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1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaints
1.4. Additional Compliance Information
None

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Violation Severity Levels
R#
R1

Lower VSL
N/A

Moderate VSL

High VSL

Severe VSL

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas that may
form islands.

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events and system studies, to
select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas
and Regional Entity areas, that
may form islands.

The Planning Coordinator failed
to develop and document
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas and
Regional Entity areas, that may
form islands.

The Planning Coordinator
identified an island(s) to serve

The Planning Coordinator
identified an island(s) to serve

OR
The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of system
studies, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas, that
may form islands.
R2

N/A
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The Planning Coordinator
identified an island(s) to

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R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

serve as a basis for designing
its UFLS program but failed to
include one (1) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its
UFLS program but failed to
include two (2) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its UFLS
program but failed to include all
of the Parts as specified in
Requirement R2, Parts 2.1, 2.2,
or 2.3.
OR
The Planning Coordinator failed
to identify any island(s) to serve
as a basis for designing its UFLS
program.

R3

N/A

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation
by UFLS entities within its
area where imbalance = [(load
— actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet one (1) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of
underfrequency conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation
by UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet two (2) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of underfrequency
conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified
island(s).,but failed to meet all
the performance characteristic
in Requirement R3, Parts 3.1,
3.2, and 3.3 in simulations of
underfrequency conditions.
OR
The Planning Coordinator failed
to develop a UFLS program

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R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
including notification of and a
schedule for implementation by
UFLS entities within its area

R4

The Planning Coordinator
conducted and documented a
UFLS assessment at least
once every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics
in Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
one (1) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

Draft 1 of PRC-006-4
October 2019r

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
two (2) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
three (3) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
R3 but simulation failed to
include four (4) or more of the
items as specified in
Requirement R4, Parts 4.1
through 4.7.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
R3 for each island identified in
Requirement R2

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R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R5

N/A

N/A

N/A

The Planning Coordinator, whose
area or portions of whose area is
part of an island identified by it
or another Planning Coordinator
which includes multiple Planning
Coordinator areas or portions of
those areas, failed to coordinate
its UFLS program design through
one of the manners described in
Requirement R5.

R6

N/A

N/A

N/A

The Planning Coordinator failed
to maintain a UFLS database for
use in event analyses and
assessments of the UFLS
program at least once each
calendar year, with no more
than 15 months between
maintenance activities.

R7

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 30 calendar days
and up to and including 40
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 40 calendar days
but less than and including 50
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 50 calendar days
but less than and including 60
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 60 calendar days
following the request.

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OR

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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator failed
to provide its UFLS database to
other Planning Coordinators.

R8

The UFLS entity provided data
to its Planning Coordinator(s)
less than or equal to 10
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 10 calendar days
but less than or equal to 15
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 15 calendar days
but less than or equal to 20
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data to
its Planning Coordinator(s) more
than 20 calendar days following
the schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided less
than 90% but more than (and
including) 85% of automatic
tripping of Load in accordance
with the UFLS program design

The UFLS entity provided less
than 85% of automatic tripping
of Load in accordance with the
UFLS program design and
schedule for implementation,

OR
The UFLS entity provided data
to its Planning Coordinator(s)
but the data was not
according to the format
specified by the Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.
R9

The UFLS entity provided less
than 100% but more than
(and including) 95% of
automatic tripping of Load in
accordance with the UFLS
Draft 1 of PRC-006-4
October 2019r

The UFLS entity provided less
than 95% but more than (and
including) 90% of automatic
tripping of Load in accordance
with the UFLS program design

OR
The UFLS entity failed to provide
data to its Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.

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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

program design and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which
it owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

including any Corrective Action
Plan, as determined by the
Planning Coordinator(s) area in
which it owns assets.

R10

The Transmission Owner
provided less than 100% but
more than (and including)
95% automatic switching of
its existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 95% but
more than (and including)
90% automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 90% but
more than (and including) 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the UFLS
program and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission Owner
owns transmission.

The Transmission Owner
provided less than 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and reactors
to control over-voltage if
required by the UFLS program
and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each Planning
Coordinator area in which the
Transmission Owner owns
transmission.

R11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of the

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,

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October 2019r

Severe VSL

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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than one year
but less than or equal to 13
months of actuation.

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than 13 months
but less than or equal to 14
months of actuation.

UFLS program, conducted and
documented an assessment of
the event and evaluated the
parts as specified in
Requirement R11, Parts 11.1
and 11.2 within a time greater
than 14 months but less than
or equal to 15 months of
actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the
initializing set points of the
UFLS program, conducted and
documented an assessment of
the event within one year of
event actuation but failed to
evaluate one (1) of the Parts
as specified in Requirement
R11, Parts11.1 or 11.2.

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Severe VSL
conducted and documented an
assessment of the event and
evaluated the parts as specified
in Requirement R11, Parts 11.1
and 11.2 within a time greater
than 15 months of actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to conduct and document
an assessment of the event and
evaluate the Parts as specified in
Requirement R11, Parts 11.1 and
11.2.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
conducted and documented an
assessment of the event within
one year of event actuation but
failed to evaluate all of the Parts

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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
as specified in Requirement R11,
Parts 11.1 and 11.2.

R12

R13

N/A

N/A

Draft 1 of PRC-006-4
October 2019r

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than two
years but less than or equal to
25 months of event actuation.

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than 25
months but less than or equal
to 26 months of event
actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, conducted and documented
a UFLS design assessment to
consider the identified
deficiencies greater than 26
months of event actuation.

N/A

N/A

The Planning Coordinator, in
whose area a BES islanding event
occurred that also included the
area(s) or portions of area(s) of
other Planning Coordinator(s) in
the same islanding event and
that resulted in system
frequency excursions below the
initializing set points of the UFLS

OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, failed to conduct and
document a UFLS design
assessment to consider the
identified deficiencies.

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R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
program, failed to coordinate its
UFLS event assessment with all
other Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event in
one of the manners described in
Requirement R13

R14

N/A

N/A

N/A

The Planning Coordinator failed
to respond to written comments
submitted by UFLS entities and
Transmission Owners within its
Planning Coordinator area
following a comment period and
before finalizing its UFLS
program, indicating in the
written response to comments
whether changes were made or
reasons why changes were not
made to the items in Parts 14.1
through 14.3.

R15

N/A

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance

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R#

Lower VSL

Draft 1 of PRC-006-4
October 2019r

Moderate VSL

High VSL

Severe VSL

characteristics in Requirement
R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period of
up to 1 month.

characteristics in Requirement
R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period
greater than 1 month but not
more than 2 months.

characteristics in Requirement
R3, but failed to develop a
Corrective Action Plan and a
schedule for implementation by
the UFLS entities within its area.
OR
The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance
characteristics in Requirement
R3, and developed a Corrective
Action Plan and a schedule for
implementation by the UFLS
entities within its area, but
exceeded the permissible time
frame for development by a
period greater than 2 months.

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PRC-006-4 — Automatic Underfrequency Load Shedding

D. Regional Variances
D.A. Regional Variance for the Quebec Interconnection
The following Interconnection-wide variance shall be applicable in the Quebec
Interconnection and replaces, in their entirety, Requirements R3 and R4 and the
violation severity levels associated with Requirements R3 and R4.
Rationale for Requirement D.A.3:
There are two modifications for requirement D.A.3 :
1. 25% Generation Deficiency : Since the Quebec Interconnection has no potential
viable BES Island in underfrequency conditions, the largest generation deficiency
scenarios are limited to extreme contingencies not already covered by RAS.
Based on Hydro-Québec TransÉnergie Transmission Planning requirements, the
stability of the network shall be maintained for extreme contingencies using a case
representing internal transfers not expected to be exceeded 25% of the time.
The Hydro-Québec TransÉnergie defense plan to cover these extreme contingencies
includes two RAS (RPTC- generation rejection and remote load shedding and TDST a centralized UVLS) and the UFLS.
2. Frequency performance curve (attachment 1A) : Specific cases where a small
generation deficiency using a peak case scenario with the minimum requirement of
spinning reserve can lead to an acceptable frequency deviation in the Quebec
Interconnection while stabilizing between the PRC-006-2 requirement (59.3 Hz) and
the UFLS anti-stall threshold (59.0 Hz).
An increase of the anti-stall threshold to 59.3 Hz would correct this situation but would
cause frequent load shedding of customers without any gain of system reliability.
Therefore, it is preferable to lower the steady state frequency minimum value to 59.0
Hz.
The delay in the performance characteristics curve is harmonized between D.A.3 and
R.3 to 60 seconds.
Rationale for Requirements D.A.3.3. and D.A.4:
The Quebec Interconnection has its own definition of BES. In Quebec, the vast
majority of BES generating plants/facilities are not directly connected to the BES. For
simulations to take into account sufficient generating resources D.A.3.3 and D.A.4
need simply refer to BES generators, plants or facilities since these are listed in a
Registry approved by Québec’s Regulatory Body (Régie de l’Énergie).

D.A.3. Each Planning Coordinator shall develop a UFLS program, including notification
of and a schedule for implementation by UFLS entities within its area, that
meets the following performance characteristics in simulations of
underfrequency conditions resulting from each of these extreme events:
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PRC-006-4 — Automatic Underfrequency Load Shedding

•

Loss of the entire capability of a generating station.

•

Loss of all transmission circuits emanating from a generating station,
switching station, substation or dc terminal.

•

Loss of all transmission circuits on a common right-of-way.

•

Three-phase fault with failure of a circuit breaker to operate and correct
operation of a breaker failure protection system and its associated breakers.

•

Three-phase fault on a circuit breaker, with normal fault clearing.

•

The operation or partial operation of a RAS for an event or condition for
which it was not intended to operate.

[VRF: High][Time Horizon: Long-term Planning]
D.A.3.1.

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-3 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-3 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than
two seconds cumulatively per simulated event, and shall not exceed
1.10 per unit for longer than 45 seconds cumulatively per simulated
event at each Quebec BES generator bus and associated generator
step-up transformer high-side bus

M.D.A.3. Each Planning Coordinator shall have evidence such as reports,
memorandums, e-mails, program plans, or other documentation of its UFLS
program, including the notification of the UFLS entities of implementation
schedule, that meet the criteria in Requirement D.A.3 Parts D.A.3.1 through
D.A.3.3.
D.A.4. Each Planning Coordinator shall conduct and document a UFLS design
assessment at least once every five years that determines through dynamic
simulation whether the UFLS program design meets the performance
characteristics in Requirement D.A.3 for each island identified in Requirement
R2. The simulation shall model each of the following; [VRF: High][Time
Horizon: Long-term Planning]

Draft 1 of PRC-006-4
October 2019

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PRC-006-4 — Automatic Underfrequency Load Shedding

D.A.4.1

Underfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip above the Generator
Underfrequency Trip Modeling curve in PRC-006-3 - Attachment 1A,
and

D.A.4.2

Overfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip below the Generator
Overfrequency Trip Modeling curve in PRC-006-3 - Attachment 1A,
and

D.A.4.3

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.A.4. Each Planning Coordinator shall have dated evidence such as reports,
dynamic simulation models and results, or other dated documentation of its
UFLS design assessment that demonstrates it meets Requirement D.A.4
Parts D.A.4.1 through D.A.4.3.

Draft 1 of PRC-006-4
October 2019

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#
DA3

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet two (2) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

Severe VSL
The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Parts D.A.3.1, D.A.3.2, and
D.A.3.3 in simulations of
underfrequency conditions
OR
The Planning Coordinator failed
to develop a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area.

DA4

N/A

Draft 1 of PRC-006-4
October 2019

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed
to include one (1) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include two (2) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include all of the items as

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL
specified in Parts D.A.4.1,
D.A.4.2 or D.A.4.3.

High VSL

Severe VSL

specified in Parts D.A.4.1, D.A.4.2
or D.A.4.3.

specified in Parts D.A.4.1, D.A.4.2
and D.A.4.3.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.A.3

Draft 1 of PRC-006-4
October 2019

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PRC-006-4 — Automatic Underfrequency Load Shedding

D.B.

Regional Variance for the Western Electricity Coordinating Council
The following Interconnection-wide variance shall be applicable in the Western
Electricity Coordinating Council (WECC) and replaces, in their entirety, Requirements R1,
R2, R3, R4, R5, R11, R12, and R13.
D.B.1. Each Planning Coordinator shall participate in a joint regional review with the
other Planning Coordinators in the WECC Regional Entity area that develops and
documents criteria, including consideration of historical events and system
studies, to select portions of the Bulk Electric System (BES) that may form
islands. [VRF: Medium][Time Horizon: Long-term Planning]
M.D.B.1. Each Planning Coordinator shall have evidence such as reports, or other
documentation of its criteria, developed as part of the joint regional review
with other Planning Coordinators in the WECC Regional Entity area to select
portions of the Bulk Electric System that may form islands including how system
studies and historical events were considered to develop the criteria per
Requirement D.B.1.
D.B.2. Each Planning Coordinator shall identify one or more islands from the regional
review (per D.B.1) to serve as a basis for designing a region-wide coordinated
UFLS program including: [VRF: Medium][Time Horizon: Long-term Planning]
D.B.2.1. Those islands selected by applying the criteria in Requirement D.B.1,
and
D.B.2.2. Any portions of the BES designed to detach from the Interconnection
(planned islands) as a result of the operation of a relay scheme or
Special Protection System.
M.D.B.2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s),
from the regional review (per D.B.1), as a basis for designing a region-wide
coordinated UFLS program that meet the criteria in Requirement D.B.2 Parts
D.B.2.1 and D.B.2.2.
D.B.3. Each Planning Coordinator shall adopt a UFLS program, coordinated across the
WECC Regional Entity area, including notification of and a schedule for
implementation by UFLS entities within its area, that meets the following
performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s).
[VRF: High][Time Horizon: Long-term Planning]
D.B.3.1.

Draft 1 of PRC-006-4
October 2019

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-3 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and

Page 25 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

D.B.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-3 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and

D.B.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two
seconds cumulatively per simulated event, and shall not exceed 1.10
per unit for longer than 45 seconds cumulatively per simulated event
at each generator bus and generator step-up transformer high-side
bus associated with each of the following:
D.B.3.3.1. Individual generating units greater than 20 MVA (gross
nameplate rating) directly connected to the BES
D.B.3.3.2. Generating plants/facilities greater than 75 MVA (gross
aggregate nameplate rating) directly connected to the
BES
D.B.3.3.3. Facilities consisting of one or more units connected to
the BES at a common bus with total generation above 75
MVA gross nameplate rating.

M.D.B.3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its adoption of a UFLS
program, coordinated across the WECC Regional Entity area, including the
notification of the UFLS entities of implementation schedule, that meet the
criteria in Requirement D.B.3 Parts D.B.3.1 through D.B.3.3.
D.B.4. Each Planning Coordinator shall participate in and document a coordinated
UFLS design assessment with the other Planning Coordinators in the WECC
Regional Entity area at least once every five years that determines through
dynamic simulation whether the UFLS program design meets the performance
characteristics in Requirement D.B.3 for each island identified in Requirement
D.B.2. The simulation shall model each of the following: [VRF: High][Time
Horizon: Long-term Planning]

Draft 1 of PRC-006-4
October 2019

D.B.4.1.

Underfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip above the Generator Underfrequency Trip Modeling curve
in PRC-006-3 - Attachment 1.

D.B.4.2.

Underfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-3 - Attachment 1.

D.B.4.3.

Underfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
above 75 MVA (gross nameplate rating) that trip above the

Page 26 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

Generator Underfrequency Trip Modeling curve in PRC-006-3 Attachment 1.
D.B.4.4.

Overfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip below the Generator Overfrequency Trip Modeling curve in
PRC-006-3 — Attachment 1.

D.B.4.5.

Overfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-3 — Attachment 1.

D.B.4.6.

Overfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
above 75 MVA (gross nameplate rating) that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-3 —
Attachment 1.

D.B.4.7.

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.B.4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its participation
in a coordinated UFLS design assessment with the other Planning Coordinators in
the WECC Regional Entity area that demonstrates it meets Requirement D.B.4
Parts D.B.4.1 through D.B.4.7.
D.B.11.

Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
participate in and document a coordinated event assessment with all affected
Planning Coordinators to conduct and document an assessment of the event
within one year of event actuation to evaluate: [VRF: Medium][Time Horizon:
Operations Assessment]
D.B.11.1. The performance of the UFLS equipment,
D.B.11.2 The effectiveness of the UFLS program

M.D.B.11. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a coordinated event assessment of the performance of the UFLS
equipment and the effectiveness of the UFLS program per Requirement D.B.11.
D.B.12.

Each Planning Coordinator, in whose islanding event assessment (per D.B.11)
UFLS program deficiencies are identified, shall participate in and document a
coordinated UFLS design assessment of the UFLS program with the other

Draft 1 of PRC-006-4
October 2019

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PRC-006-4 — Automatic Underfrequency Load Shedding

Planning Coordinators in the WECC Regional Entity area to consider the
identified deficiencies within two years of event actuation. [VRF: Medium][Time
Horizon: Operations Assessment]
M.D.B.12. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a UFLS design assessment per Requirements D.B.12 and D.B.4 if
UFLS program deficiencies are identified in D.B.11.

Draft 1 of PRC-006-4
October 2019

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#
D.B.1

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical
events, to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical events
and system studies, to select
portions of the BES, including
interconnected portions of the
BES in adjacent Planning
Coordinator areas, that may form
islands

OR

Severe VSL
The Planning Coordinator failed
to participate in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of system studies,
to select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands

Draft 1 of PRC-006-4
October 2019

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#
D.B.2

Lower VSL

Moderate VSL

High VSL

N/A
N/A

The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include one
(1) of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2

Severe VSL
The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include all
of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2
OR
The Planning Coordinator failed
to identify any island(s) from the
regional review to serve as a
basis for designing its UFLS
program.

D.B.3

N/A

Draft 1 of PRC-006-4
October 2019

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, or D.B.3.3 in
simulations of underfrequency
conditions

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that included
notification of and a schedule for
implementation by UFLS entities
within its area, but failed to meet
two (2) of the performance
characteristic in Requirement
D.B.3, Parts D.B.3.1, D.B.3.2, or
D.B.3.3 in simulations of
underfrequency conditions

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, and D.B.3.3 in
simulations of underfrequency
conditions

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
OR
The Planning Coordinator failed
to adopt a UFLS program,
coordinated across the WECC
Regional Entity area, including
notification of and a schedule for
implementation by UFLS entities
within its area.

D.B.4

The Planning Coordinator
participated in and
documented a coordinated
UFLS assessment with the other
Planning Coordinators in the
WECC Regional Entity area at
least once every five years that
determines through dynamic
simulation whether the UFLS
program design meets the
performance characteristics in
Requirement D.B.3 for each
island identified in Requirement
D.B.2 but the simulation failed
to include one (1) of the items
as specified in Requirement
D.B.4, Parts D.B.4.1 through
D.B.4.7.

Draft 1 of PRC-006-4
October 2019

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include two
(2) of the items as specified in
Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include three
(3) of the items as specified in
Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include four
(4) or more of the items as
specified in Requirement D.B.4,
Parts D.B.4.1 through D.B.4.7.
OR

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator failed
to participate in and document a
coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2

D.B.11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below the
initializing set points of the
UFLS program, participated in
and documented a coordinated
event assessment with all
Planning Coordinators whose
areas or portions of whose
areas were also included in the
same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than one year but
Draft 1 of PRC-006-4
October 2019

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 13 months but

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 14 months but

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL
less than or equal to 13 months
of actuation.

Draft 1 of PRC-006-4
October 2019

Moderate VSL
less than or equal to 14 months
of actuation.

High VSL

Severe VSL

less than or equal to 15 months
of actuation.

time greater than 15 months of
actuation.

OR

OR

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event
within one year of event
actuation but failed to evaluate
one (1) of the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 or D.B.11.2.

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to participate in and
document a coordinated event
assessment with all Planning
Coordinators whose areas or
portion of whose areas were also
included in the same island event
and evaluate the parts as
specified in Requirement D.B.11,
Parts D.B.11.1 and D.B.11.2.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
in the same islanding event
within one year of event
actuation but failed to evaluate
all of the parts as specified in
Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2.

D.B.12

N/A

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than two
years but less than or equal to 25
months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 25
months but less than or equal to
26 months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 26
months of event actuation.
OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, failed to participate in
and document a coordinated
UFLS design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area

Draft 1 of PRC-006-4
October 2019

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
to consider the identified
deficiencies

Draft 1 of PRC-006-4
October 2019

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PRC-006-4 — Automatic Underfrequency Load Shedding

E. Associated Documents
Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

May 25, 2010

Completed revision, merging and
updating PRC-006-0, PRC-007-0 and
PRC-009-0.

1

November 4, 2010

Adopted by the Board of Trustees

1

May 7, 2012

FERC Order issued approving PRC006-1 (approval becomes effective
July 10, 2012)

1

November 9, 2012

2

November 13, 2014

FERC Letter Order issued accepting
the modification of the VRF in R5
from (Medium to High) and the
modification of the VSL language in
R8.
Adopted by the Board of Trustees

Revisions made under
Project 2008-02:
Undervoltage Load
Shedding (UVLS) &
Underfrequency Load
Shedding (UFLS) to address
directive issued in FERC
Order No. 763.
Revisions to existing
Requirement R9 and
R10 and addition of
new Requirement
R15.

3

August 10, 2017

4

Draft 1 of PRC-006-4
October 2019

Adopted by the NERC Board of
Trustees
Adopted by the NERC Board of
Trustees

Revisions to the Regional
Variance for the Quebec
Interconnection.

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PRC-006-4 — Automatic Underfrequency Load Shedding

PRC-006-3 – Attachment 1
Underfrequency Load Shedding Program
Design Performance and Modeling Curves for
Requirements R3 Parts 3.1-3.2 and R4 Parts 4.1-4.6
63

Overfrequency Trip Settings
Must Be Modeled for Generators
That Trip Below the Generator
Overfrequency Trip Modeling
Curve

62

Simulated Frequency Must
Remain Between the
Overfrequency and
Underfrequency Performance
Characteristic Curves

60

59

58

Underfrequency Trip Settings
Must Be Modeled for Generators
That Trip Above the Generator
Underfrequency Trip Modeling
Curve

57
0.1

1

Time (sec)

10

100

Generator Overfrequency Trip Modeling (Requirement R4 Parts 4.4-4.6)
Overfrequency Performance Characteristic (Requirement R3 Part 3.2)
Underfrequency Performance Characteristic (Requirement R3 Part 3.1)
Generator Underfrequency Trip Modeling (Requirement R4 Parts 4.1-4.3)

Curve Definitions
Generator Overfrequency Trip Modeling

Overfrequency Performance Characteristic

t≤2s

t>2s

t≤4s

4 s < t ≤ 30 s

t > 30 s

f = 62.2
Hz

f = -0.686log(t) + 62.41
Hz

f = 61.8
Hz

f = -0.686log(t) + 62.21
Hz

f = 60.7
Hz

Draft 1 of PRC-006-4
October 2019

Page 37 of 40

Frequency (Hz)

61

PRC-006-4 — Automatic Underfrequency Load Shedding

Generator Underfrequency Trip
Modeling

Underfrequency Performance Characteristic

t≤2s

t>2s

t≤2s

2 s < t ≤ 60 s

t > 60 s

f = 57.8
Hz

f = 0.575log(t) + 57.63
Hz

f = 58.0
Hz

f = 0.575log(t) + 57.83
Hz

f = 59.3
Hz

Draft 1 of PRC-006-4
October 2019

Page 38 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

Draft 1 of PRC-006-4
October 2019

Page 39 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

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 R9:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a Planning Coordinator (PC)
assessment. The revised language adds clarity by requiring that each UFLS entity follow the
UFLS program, including any Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R10:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a PC assessment. The revised
language adds clarity by requiring that each UFLS entity follow the UFLS program, including any
Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R15:
Requirement R15 was added in response to the directive from FERC Order No. 763, which
raised concern that the standard failed to specify how soon an entity would need to implement
corrections after a deficiency is identified by a PC assessment. Requirement R15 addresses the
FERC directive by making explicit that if deficiencies are identified as a result of an assessment,
the PC shall develop a Corrective Action Plan and schedule for implementation by the UFLS
entities.
A “Corrective Action Plan” is defined in the NERC Glossary of Terms as, “a list of actions and an
associated timetable for implementation to remedy a specific problem.” Thus, the Corrective
Action Plan developed by the PC will identify the specific timeframe for an entity to implement
corrections to remedy any deficiencies identified by the PC as a result of an assessment.

Draft 1 of PRC-006-4
October 2019

Page 40 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
A. Introduction
1.
Title:
Automatic Underfrequency Load Shedding
2.

Number:

3.

Purpose: To establish design and documentation requirements for automatic
underfrequency load shedding (UFLS) programs to arrest declining frequency, assist
recovery of frequency following underfrequency events and provide last resort
system preservation measures.

4.

Applicability:

PRC-006-3 4

4.1. Planning Coordinators
4.2. UFLS entities shall mean all entities that are responsible for the ownership,
operation, or control of UFLS equipment as required by the UFLS program
established by the Planning Coordinators. Such entities may include one or
more of the following:
4.2.1 Transmission Owners
4.2.2

4.2.2 Distribution Providers
4.2.3 UFLS-Only Distribution Providers1

4.3. Transmission Owners that own Elements identified in the UFLS program
established by the Planning Coordinators.
5.

Effective Date:
See Implementation Plan
This standard is effective on the first day of the first calendar quarter six months 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.

6.

Background:
PRC-006-2 was developed under Project 2008-02: Underfrequency Load Shedding
(UFLS). The drafting team revised PRC-006-1 for the purpose of addressing the
directive issued in FERC Order No. 763. Automatic Underfrequency Load Shedding and
Load Shedding Plans Reliability Standards, 139 FERC ¶ 61,098 (2012).

1

NERC Rules of Procedure, Appendix 5
https://www.nerc.com/FilingsOrders/us/RuleOfProcedureDL/NERC_ROP_Effective_20160504.pdf

Page 1 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
B. Requirements and Measures
R1.

Each Planning Coordinator shall develop and document criteria, including
consideration of historical events and system studies, to select portions of the Bulk
Electric System (BES), including interconnected portions of the BES in adjacent
Planning Coordinator areas and Regional Entity areas that may form islands. [VRF:
Medium][Time Horizon: Long-term Planning]

M1. Each Planning Coordinator shall have evidence such as reports, or other documentation
of its criteria to select portions of the Bulk Electric System that may form islands
including how system studies and historical events were considered to develop the
criteria per Requirement R1.
R2.

Each Planning Coordinator shall identify one or more islands to serve as a basis for
designing its UFLS program including: [VRF: Medium][Time Horizon: Long-term
Planning]
2.1. Those islands selected by applying the criteria in Requirement R1, and
2.2. Any portions of the BES designed to detach from the Interconnection (planned
islands) as a result of the operation of a relay scheme or Special Protection
System, and
2.3. A single island that includes all portions of the BES in either the Regional Entity
area or the Interconnection in which the Planning Coordinator’s area resides. If a
Planning Coordinator’s area resides in multiple Regional Entity areas, each of
those Regional Entity areas shall be identified as an island. Planning Coordinators
may adjust island boundaries to differ from Regional Entity area boundaries by
mutual consent where necessary for the sole purpose of producing contiguous
regional islands more suitable for simulation.

M2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s) as a basis
for designing a UFLS program that meet the criteria in Requirement R2, Parts 2.1
through 2.3.
R3.

Each Planning Coordinator shall develop a UFLS program, including notification of and
a schedule for implementation by UFLS entities within its area, that meets the
following performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s). [VRF:
High][Time Horizon: Long-term Planning]
3.1. Frequency shall remain above the Underfrequency Performance Characteristic
curve in PRC-006-3 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
3.2. Frequency shall remain below the Overfrequency Performance Characteristic
curve in PRC-006-3 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
Page 2 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
3.3. Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two seconds
cumulatively per simulated event, and shall not exceed 1.10 per unit for longer
than 45 seconds cumulatively per simulated event at each generator bus and
generator step-up transformer high-side bus associated with each of the
following:
• Individual generating units greater than 20 MVA (gross nameplate rating)
directly connected to the BES
• Generating plants/facilities greater than 75 MVA (gross aggregate nameplate
rating) directly connected to the BES
• Facilities consisting of one or more units connected to the BES at a common
bus with total generation above 75 MVA gross nameplate rating.
M3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its UFLS program, including the
notification of the UFLS entities of implementation schedule, that meet the criteria in
Requirement R3, Parts 3.1 through 3.3.
R4.

Each Planning Coordinator shall conduct and document a UFLS design assessment at
least once every five years that determines through dynamic simulation whether the
UFLS program design meets the performance characteristics in Requirement R3 for
each island identified in Requirement R2. The simulation shall model each of the
following: [VRF: High][Time Horizon: Long-term Planning]
4.1. Underfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip above the
Generator Underfrequency Trip Modeling curve in PRC-006-3 - Attachment 1.
4.2. Underfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip above
the Generator Underfrequency Trip Modeling curve in PRC-006-3 - Attachment 1.
4.3. Underfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-3 - Attachment 1.
4.4. Overfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-3 — Attachment 1.
4.5. Overfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip below
the Generator Overfrequency Trip Modeling curve in PRC-006-3 — Attachment 1.
4.6. Overfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA

Page 3 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
(gross nameplate rating) that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-3 — Attachment 1.
4.7. Any automatic Load restoration that impacts frequency stabilization and operates
within the duration of the simulations run for the assessment.
M4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its UFLS design
assessment that demonstrates it meets Requirement R4, Parts 4.1 through 4.7.
R5.

Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall coordinate its UFLS program design
with all other Planning Coordinators whose areas or portions of whose areas are also
part of the same identified island through one of the following: [VRF: High][Time
Horizon: Long-term Planning]
•

Develop a common UFLS program design and schedule for implementation per
Requirement R3 among the Planning Coordinators whose areas or portions of
whose areas are part of the same identified island, or

•

Conduct a joint UFLS design assessment per Requirement R4 among the Planning
Coordinators whose areas or portions of whose areas are part of the same
identified island, or

•

Conduct an independent UFLS design assessment per Requirement R4 for the
identified island, and in the event the UFLS design assessment fails to meet
Requirement R3, identify modifications to the UFLS program(s) to meet
Requirement R3 and report these modifications as recommendations to the other
Planning Coordinators whose areas or portions of whose areas are also part of
the same identified island and the ERO.

M5. Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall have dated evidence such as joint
UFLS program design documents, reports describing a joint UFLS design assessment,
letters that include recommendations, or other dated documentation demonstrating
that it coordinated its UFLS program design with all other Planning Coordinators whose
areas or portions of whose areas are also part of the same identified island per
Requirement R5.
R6.

Each Planning Coordinator shall maintain a UFLS database containing data necessary to
model its UFLS program for use in event analyses and assessments of the UFLS
program at least once each calendar year, with no more than 15 months between
maintenance activities. [VRF: Lower][Time Horizon: Long-term Planning]

M6. Each Planning Coordinator shall have dated evidence such as a UFLS database, data
requests, data input forms, or other dated documentation to show that it maintained a
UFLS database for use in event analyses and assessments of the UFLS program per

Page 4 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
Requirement R6 at least once each calendar year, with no more than 15 months
between maintenance activities.
R7.

Each Planning Coordinator shall provide its UFLS database containing data necessary to
model its UFLS program to other Planning Coordinators within its Interconnection
within 30 calendar days of a request. [VRF: Lower][Time Horizon: Long-term Planning]

M7. Each Planning Coordinator shall have dated evidence such as letters, memorandums,
e-mails or other dated documentation that it provided their UFLS database to other
Planning Coordinators within their Interconnection within 30 calendar days of a
request per Requirement R7.
R8.

Each UFLS entity shall provide data to its Planning Coordinator(s) according to the
format and schedule specified by the Planning Coordinator(s) to support maintenance
of each Planning Coordinator’s UFLS database. [VRF: Lower][Time Horizon: Long-term
Planning]

M8. Each UFLS Entity shall have dated evidence such as responses to data requests,
spreadsheets, letters or other dated documentation that it provided data to its
Planning Coordinator according to the format and schedule specified by the Planning
Coordinator to support maintenance of the UFLS database per Requirement R8.
R9.

Each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
as determined by its Planning Coordinator(s) in each Planning Coordinator area in
which it owns assets. [VRF: High][Time Horizon: Long-term Planning]

M9. Each UFLS Entity shall have dated evidence such as spreadsheets summarizing feeder
load armed with UFLS relays, spreadsheets with UFLS relay settings, or other dated
documentation that it provided automatic tripping of load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
per Requirement R9.
R10. Each Transmission Owner shall provide automatic switching of its existing capacitor
banks, Transmission Lines, and reactors to control over-voltage as a result of
underfrequency load shedding if required by the UFLS program and schedule for
implementation, including any Corrective Action Plan, as determined by the Planning
Coordinator(s) in each Planning Coordinator area in which the Transmission Owner
owns transmission. [VRF: High][Time Horizon: Long-term Planning]
M10. Each Transmission Owner shall have dated evidence such as relay settings, tripping
logic or other dated documentation that it provided automatic switching of its existing
capacitor banks, Transmission Lines, and reactors in order to control over-voltage as a
result of underfrequency load shedding if required by the UFLS program and schedule
for implementation, including any Corrective Action Plan, per Requirement R10.
R11. Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall

Page 5 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
conduct and document an assessment of the event within one year of event actuation
to evaluate: [VRF: Medium][Time Horizon: Operations Assessment]
11.1. The performance of the UFLS equipment,
11.2. The effectiveness of the UFLS program.
M11. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted an
event assessment of the performance of the UFLS equipment and the effectiveness of
the UFLS program per Requirement R11.
R12. Each Planning Coordinator, in whose islanding event assessment (per R11) UFLS
program deficiencies are identified, shall conduct and document a UFLS design
assessment to consider the identified deficiencies within two years of event actuation.
[VRF: Medium][Time Horizon: Operations Assessment]
M12. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted a
UFLS design assessment per Requirements R12 and R4 if UFLS program deficiencies are
identified in R11.
R13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall coordinate its event assessment (in accordance
with Requirement R11) with all other Planning Coordinators whose areas or portions of
whose areas were also included in the same islanding event through one of the
following: [VRF: Medium][Time Horizon: Operations Assessment]
•

Conduct a joint event assessment per Requirement R11 among the Planning
Coordinators whose areas or portions of whose areas were included in the same
islanding event, or

•

Conduct an independent event assessment per Requirement R11 that reaches
conclusions and recommendations consistent with those of the event
assessments of the other Planning Coordinators whose areas or portions of
whose areas were included in the same islanding event, or

•

Conduct an independent event assessment per Requirement R11 and where the
assessment fails to reach conclusions and recommendations consistent with
those of the event assessments of the other Planning Coordinators whose areas
or portions of whose areas were included in the same islanding event, identify
differences in the assessments that likely resulted in the differences in the
conclusions and recommendations and report these differences to the other
Planning Coordinators whose areas or portions of whose areas were included in
the same islanding event and the ERO.

M13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
Page 6 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall have dated evidence such as a joint assessment
report, independent assessment reports and letters describing likely reasons for
differences in conclusions and recommendations, or other dated documentation
demonstrating it coordinated its event assessment (per Requirement R11) with all
other Planning Coordinator(s) whose areas or portions of whose areas were also
included in the same islanding event per Requirement R13.
R14. Each Planning Coordinator shall respond to written comments submitted by UFLS
entities and Transmission Owners within its Planning Coordinator area following a
comment period and before finalizing its UFLS program, indicating in the written
response to comments whether changes will be made or reasons why changes will not
be made to the following [VRF: Lower][Time Horizon: Long-term Planning]:
14.1. UFLS program, including a schedule for implementation
14.2. UFLS design assessment
14.3. Format and schedule of UFLS data submittal
M14. Each Planning Coordinator shall have dated evidence of responses, such as e-mails and
letters, to written comments submitted by UFLS entities and Transmission Owners
within its Planning Coordinator area following a comment period and before finalizing
its UFLS program per Requirement R14.
R15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall develop a Corrective Action Plan
and a schedule for implementation by the UFLS entities within its area. [VRF:
High][Time Horizon: Long-term Planning]
15.1. For UFLS design assessments performed under Requirement R4 or R5, the
Corrective Action Plan shall be developed within the five-year time frame
identified in Requirement R4.
15.2. For UFLS design assessments performed under Requirement R12, the Corrective
Action Plan shall be developed within the two-year time frame identified in
Requirement R12.
M15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall have a dated Corrective Action
Plan and a schedule for implementation by the UFLS entities within its area, that was
developed within the time frame identified in Part 15.1 or 15.2.

Page 7 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” (CEA)
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
Each Planning Coordinator and UFLS entity shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
•

Each Planning Coordinator shall retain the current evidence of Requirements
R1, R2, R3, R4, R5, R12, R14, and R15, Measures M1, M2, M3, M4, M5, M12,
M14, and M15 as well as any evidence necessary to show compliance since
the last compliance audit.

•

Each Planning Coordinator shall retain the current evidence of UFLS database
update in accordance with Requirement R6, Measure M6, and evidence of the
prior year’s UFLS database update.

•

Each Planning Coordinator shall retain evidence of any UFLS database
transmittal to another Planning Coordinator since the last compliance audit in
accordance with Requirement R7, Measure M7.

•

Each UFLS entity shall retain evidence of UFLS data transmittal to the Planning
Coordinator(s) since the last compliance audit in accordance with
Requirement R8, Measure M8.

•

Each UFLS entity shall retain the current evidence of adherence with the UFLS
program in accordance with Requirement R9, Measure M9, and evidence of
adherence since the last compliance audit.

•

Transmission Owner shall retain the current evidence of adherence with the
UFLS program in accordance with Requirement R10, Measure M10, and
evidence of adherence since the last compliance audit.

•

Each Planning Coordinator shall retain evidence of Requirements R11, and
R13, and Measures M11, and M13 for 6 calendar years.

If a Planning Coordinator or UFLS entity is found non-compliant, it shall keep
information related to the non-compliance until found compliant or for the
retention period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.

Page 8 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaints
1.4. Additional Compliance Information
None

Page 9 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

2.
R#
R1

Violation Severity Levels
Lower VSL

N/A

Moderate VSL

High VSL

Severe VSL

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas that may
form islands.

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events and system studies, to
select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas
and Regional Entity areas, that
may form islands.

The Planning Coordinator failed
to develop and document
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas and
Regional Entity areas, that may
form islands.

The Planning Coordinator
identified an island(s) to serve

The Planning Coordinator
identified an island(s) to serve

OR
The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of system
studies, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas, that
may form islands.
R2

N/A

The Planning Coordinator
identified an island(s) to

Page 10 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

serve as a basis for designing
its UFLS program but failed to
include one (1) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its
UFLS program but failed to
include two (2) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its UFLS
program but failed to include all
of the Parts as specified in
Requirement R2, Parts 2.1, 2.2,
or 2.3.
OR
The Planning Coordinator failed
to identify any island(s) to serve
as a basis for designing its UFLS
program.

R3

N/A

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation
by UFLS entities within its
area where imbalance = [(load
— actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet one (1) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of
underfrequency conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation
by UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet two (2) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of underfrequency
conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified
island(s).,but failed to meet all
the performance characteristic
in Requirement R3, Parts 3.1,
3.2, and 3.3 in simulations of
underfrequency conditions.
OR
The Planning Coordinator failed
to develop a UFLS program

Page 11 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
including notification of and a
schedule for implementation by
UFLS entities within its area

R4

The Planning Coordinator
conducted and documented a
UFLS assessment at least
once every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics
in Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
one (1) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
two (2) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
three (3) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

Page 12 of 40

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
R3 but simulation failed to
include four (4) or more of the
items as specified in
Requirement R4, Parts 4.1
through 4.7.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
R3 for each island identified in
Requirement R2

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R5

N/A

N/A

N/A

The Planning Coordinator, whose
area or portions of whose area is
part of an island identified by it
or another Planning Coordinator
which includes multiple Planning
Coordinator areas or portions of
those areas, failed to coordinate
its UFLS program design through
one of the manners described in
Requirement R5.

R6

N/A

N/A

N/A

The Planning Coordinator failed
to maintain a UFLS database for
use in event analyses and
assessments of the UFLS
program at least once each
calendar year, with no more
than 15 months between
maintenance activities.

R7

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 30 calendar days
and up to and including 40
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 40 calendar days
but less than and including 50
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 50 calendar days
but less than and including 60
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 60 calendar days
following the request.

Page 13 of 40

OR

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator failed
to provide its UFLS database to
other Planning Coordinators.

R8

The UFLS entity provided data
to its Planning Coordinator(s)
less than or equal to 10
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 10 calendar days
but less than or equal to 15
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 15 calendar days
but less than or equal to 20
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data to
its Planning Coordinator(s) more
than 20 calendar days following
the schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided less
than 90% but more than (and
including) 85% of automatic
tripping of Load in accordance
with the UFLS program design

The UFLS entity provided less
than 85% of automatic tripping
of Load in accordance with the
UFLS program design and
schedule for implementation,

OR
The UFLS entity provided data
to its Planning Coordinator(s)
but the data was not
according to the format
specified by the Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.
R9

The UFLS entity provided less
than 100% but more than
(and including) 95% of
automatic tripping of Load in
accordance with the UFLS

The UFLS entity provided less
than 95% but more than (and
including) 90% of automatic
tripping of Load in accordance
with the UFLS program design

Page 14 of 40

OR
The UFLS entity failed to provide
data to its Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

program design and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which
it owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

including any Corrective Action
Plan, as determined by the
Planning Coordinator(s) area in
which it owns assets.

R10

The Transmission Owner
provided less than 100% but
more than (and including)
95% automatic switching of
its existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 95% but
more than (and including)
90% automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 90% but
more than (and including) 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the UFLS
program and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission Owner
owns transmission.

The Transmission Owner
provided less than 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and reactors
to control over-voltage if
required by the UFLS program
and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each Planning
Coordinator area in which the
Transmission Owner owns
transmission.

R11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of the

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,

Page 15 of 40

Severe VSL

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than one year
but less than or equal to 13
months of actuation.

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than 13 months
but less than or equal to 14
months of actuation.

UFLS program, conducted and
documented an assessment of
the event and evaluated the
parts as specified in
Requirement R11, Parts 11.1
and 11.2 within a time greater
than 14 months but less than
or equal to 15 months of
actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the
initializing set points of the
UFLS program, conducted and
documented an assessment of
the event within one year of
event actuation but failed to
evaluate one (1) of the Parts
as specified in Requirement
R11, Parts11.1 or 11.2.

Page 16 of 40

Severe VSL
conducted and documented an
assessment of the event and
evaluated the parts as specified
in Requirement R11, Parts 11.1
and 11.2 within a time greater
than 15 months of actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to conduct and document
an assessment of the event and
evaluate the Parts as specified in
Requirement R11, Parts 11.1 and
11.2.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
conducted and documented an
assessment of the event within
one year of event actuation but
failed to evaluate all of the Parts

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
as specified in Requirement R11,
Parts 11.1 and 11.2.

R12

R13

N/A

N/A

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than two
years but less than or equal to
25 months of event actuation.

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than 25
months but less than or equal
to 26 months of event
actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, conducted and documented
a UFLS design assessment to
consider the identified
deficiencies greater than 26
months of event actuation.

N/A

N/A

The Planning Coordinator, in
whose area a BES islanding event
occurred that also included the
area(s) or portions of area(s) of
other Planning Coordinator(s) in
the same islanding event and
that resulted in system
frequency excursions below the
initializing set points of the UFLS

Page 17 of 40

OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, failed to conduct and
document a UFLS design
assessment to consider the
identified deficiencies.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
program, failed to coordinate its
UFLS event assessment with all
other Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event in
one of the manners described in
Requirement R13

R14

N/A

N/A

N/A

The Planning Coordinator failed
to respond to written comments
submitted by UFLS entities and
Transmission Owners within its
Planning Coordinator area
following a comment period and
before finalizing its UFLS
program, indicating in the
written response to comments
whether changes were made or
reasons why changes were not
made to the items in Parts 14.1
through 14.3.

R15

N/A

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance
characteristics in Requirement

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance
characteristics in Requirement

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance
characteristics in Requirement

Page 18 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period of
up to 1 month.

R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period
greater than 1 month but not
more than 2 months.

R3, but failed to develop a
Corrective Action Plan and a
schedule for implementation by
the UFLS entities within its area.

Page 19 of 40

OR
The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance
characteristics in Requirement
R3, and developed a Corrective
Action Plan and a schedule for
implementation by the UFLS
entities within its area, but
exceeded the permissible time
frame for development by a
period greater than 2 months.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D. Regional Variances
D.A. Regional Variance for the Quebec Interconnection
The following Interconnection-wide variance shall be applicable in the Quebec
Interconnection and replaces, in their entirety, Requirements R3 and R4 and the
violation severity levels associated with Requirements R3 and R4.
Rationale for Requirement D.A.3:
There are two modifications for requirement D.A.3 :
1. 25% Generation Deficiency : Since the Quebec Interconnection has no potential
viable BES Island in underfrequency conditions, the largest generation deficiency
scenarios are limited to extreme contingencies not already covered by RAS.
Based on Hydro-Québec TransÉnergie Transmission Planning requirements, the
stability of the network shall be maintained for extreme contingencies using a case
representing internal transfers not expected to be exceeded 25% of the time.
The Hydro-Québec TransÉnergie defense plan to cover these extreme contingencies
includes two RAS (RPTC- generation rejection and remote load shedding and TDST a centralized UVLS) and the UFLS.
2. Frequency performance curve (attachment 1A) : Specific cases where a small
generation deficiency using a peak case scenario with the minimum requirement of
spinning reserve can lead to an acceptable frequency deviation in the Quebec
Interconnection while stabilizing between the PRC-006-2 requirement (59.3 Hz) and
the UFLS anti-stall threshold (59.0 Hz).
An increase of the anti-stall threshold to 59.3 Hz would correct this situation but would
cause frequent load shedding of customers without any gain of system reliability.
Therefore, it is preferable to lower the steady state frequency minimum value to 59.0
Hz.
The delay in the performance characteristics curve is harmonized between D.A.3 and
R.3 to 60 seconds.
Rationale for Requirements D.A.3.3. and D.A.4:
The Quebec Interconnection has its own definition of BES. In Quebec, the vast
majority of BES generating plants/facilities are not directly connected to the BES. For
simulations to take into account sufficient generating resources D.A.3.3 and D.A.4
need simply refer to BES generators, plants or facilities since these are listed in a
Registry approved by Québec’s Regulatory Body (Régie de l’Énergie).

D.A.3. Each Planning Coordinator shall develop a UFLS program, including notification
of and a schedule for implementation by UFLS entities within its area, that

Page 20 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
meets the following performance characteristics in simulations of
underfrequency conditions resulting from each of these extreme events:
•

Loss of the entire capability of a generating station.

•

Loss of all transmission circuits emanating from a generating
station, switching station, substation or dc terminal.

•

Loss of all transmission circuits on a common right-of-way.

•

Three-phase fault with failure of a circuit breaker to operate and
correct operation of a breaker failure protection system and its
associated breakers.

•

Three-phase fault on a circuit breaker, with normal fault clearing.

•

The operation or partial operation of a RAS for an event or
condition for which it was not intended to operate.

[VRF: High][Time Horizon: Long-term Planning]
D.A.3.1.

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-3 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-3 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than
two seconds cumulatively per simulated event, and shall not exceed
1.10 per unit for longer than 45 seconds cumulatively per simulated
event at each Quebec BES generator bus and associated generator
step-up transformer high-side bus

M.D.A.3. Each Planning Coordinator shall have evidence such as reports,
memorandums, e-mails, program plans, or other documentation of its UFLS
program, including the notification of the UFLS entities of implementation
schedule, that meet the criteria in Requirement D.A.3 Parts D.A.3.1 through
D.A.3.3.
D.A.4. Each Planning Coordinator shall conduct and document a UFLS design
assessment at least once every five years that determines through dynamic
Page 21 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
simulation whether the UFLS program design meets the performance
characteristics in Requirement D.A.3 for each island identified in Requirement
R2. The simulation shall model each of the following; [VRF: High][Time
Horizon: Long-term Planning]
D.A.4.1

Underfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip above the Generator
Underfrequency Trip Modeling curve in PRC-006-3 - Attachment 1A,
and

D.A.4.2

Overfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip below the Generator
Overfrequency Trip Modeling curve in PRC-006-3 - Attachment 1A,
and

D.A.4.3

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.A.4. Each Planning Coordinator shall have dated evidence such as reports,
dynamic simulation models and results, or other dated documentation of its
UFLS design assessment that demonstrates it meets Requirement D.A.4
Parts D.A.4.1 through D.A.4.3.

Page 22 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#
DA3

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet two (2) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

Severe VSL
The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Parts D.A.3.1, D.A.3.2, and
D.A.3.3 in simulations of
underfrequency conditions
OR
The Planning Coordinator failed
to develop a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area.

DA4

N/A

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed
to include one (1) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include two (2) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include all of the items as
Page 23 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL
specified in Parts D.A.4.1,
D.A.4.2 or D.A.4.3.

High VSL

Severe VSL

specified in Parts D.A.4.1, D.A.4.2
or D.A.4.3.

specified in Parts D.A.4.1, D.A.4.2
and D.A.4.3.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.A.3

Page 24 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D.B.

Regional Variance for the Western Electricity Coordinating Council
The following Interconnection-wide variance shall be applicable in the Western
Electricity Coordinating Council (WECC) and replaces, in their entirety, Requirements R1,
R2, R3, R4, R5, R11, R12, and R13.
D.B.1. Each Planning Coordinator shall participate in a joint regional review with the
other Planning Coordinators in the WECC Regional Entity area that develops and
documents criteria, including consideration of historical events and system
studies, to select portions of the Bulk Electric System (BES) that may form
islands. [VRF: Medium][Time Horizon: Long-term Planning]
M.D.B.1. Each Planning Coordinator shall have evidence such as reports, or other
documentation of its criteria, developed as part of the joint regional review
with other Planning Coordinators in the WECC Regional Entity area to select
portions of the Bulk Electric System that may form islands including how system
studies and historical events were considered to develop the criteria per
Requirement D.B.1.
D.B.2. Each Planning Coordinator shall identify one or more islands from the regional
review (per D.B.1) to serve as a basis for designing a region-wide coordinated
UFLS program including: [VRF: Medium][Time Horizon: Long-term Planning]
D.B.2.1. Those islands selected by applying the criteria in Requirement D.B.1,
and
D.B.2.2. Any portions of the BES designed to detach from the Interconnection
(planned islands) as a result of the operation of a relay scheme or
Special Protection System.
M.D.B.2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s),
from the regional review (per D.B.1), as a basis for designing a region-wide
coordinated UFLS program that meet the criteria in Requirement D.B.2 Parts
D.B.2.1 and D.B.2.2.
D.B.3. Each Planning Coordinator shall adopt a UFLS program, coordinated across the
WECC Regional Entity area, including notification of and a schedule for
implementation by UFLS entities within its area, that meets the following
performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s).
[VRF: High][Time Horizon: Long-term Planning]
D.B.3.1.

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-3 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and
Page 25 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D.B.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-3 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and

D.B.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two
seconds cumulatively per simulated event, and shall not exceed 1.10
per unit for longer than 45 seconds cumulatively per simulated event
at each generator bus and generator step-up transformer high-side
bus associated with each of the following:
D.B.3.3.1. Individual generating units greater than 20 MVA (gross
nameplate rating) directly connected to the BES
D.B.3.3.2. Generating plants/facilities greater than 75 MVA (gross
aggregate nameplate rating) directly connected to the
BES
D.B.3.3.3. Facilities consisting of one or more units connected to
the BES at a common bus with total generation above 75
MVA gross nameplate rating.

M.D.B.3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its adoption of a UFLS
program, coordinated across the WECC Regional Entity area, including the
notification of the UFLS entities of implementation schedule, that meet the
criteria in Requirement D.B.3 Parts D.B.3.1 through D.B.3.3.
D.B.4. Each Planning Coordinator shall participate in and document a coordinated
UFLS design assessment with the other Planning Coordinators in the WECC
Regional Entity area at least once every five years that determines through
dynamic simulation whether the UFLS program design meets the performance
characteristics in Requirement D.B.3 for each island identified in Requirement
D.B.2. The simulation shall model each of the following: [VRF: High][Time
Horizon: Long-term Planning]
D.B.4.1.

Underfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip above the Generator Underfrequency Trip Modeling curve
in PRC-006-3 - Attachment 1.

D.B.4.2.

Underfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-3 - Attachment 1.

D.B.4.3.

Underfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
Page 26 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
above 75 MVA (gross nameplate rating) that trip above the
Generator Underfrequency Trip Modeling curve in PRC-006-3 Attachment 1.
D.B.4.4.

Overfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip below the Generator Overfrequency Trip Modeling curve in
PRC-006-3 — Attachment 1.

D.B.4.5.

Overfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-3 — Attachment 1.

D.B.4.6.

Overfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
above 75 MVA (gross nameplate rating) that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-3 —
Attachment 1.

D.B.4.7.

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.B.4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its participation
in a coordinated UFLS design assessment with the other Planning Coordinators in
the WECC Regional Entity area that demonstrates it meets Requirement D.B.4
Parts D.B.4.1 through D.B.4.7.
D.B.11.

Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
participate in and document a coordinated event assessment with all affected
Planning Coordinators to conduct and document an assessment of the event
within one year of event actuation to evaluate: [VRF: Medium][Time Horizon:
Operations Assessment]
D.B.11.1. The performance of the UFLS equipment,
D.B.11.2 The effectiveness of the UFLS program

M.D.B.11. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a coordinated event assessment of the performance of the UFLS
equipment and the effectiveness of the UFLS program per Requirement D.B.11.

Page 27 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D.B.12.

Each Planning Coordinator, in whose islanding event assessment (per D.B.11)
UFLS program deficiencies are identified, shall participate in and document a
coordinated UFLS design assessment of the UFLS program with the other
Planning Coordinators in the WECC Regional Entity area to consider the
identified deficiencies within two years of event actuation. [VRF: Medium][Time
Horizon: Operations Assessment]

M.D.B.12. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a UFLS design assessment per Requirements D.B.12 and D.B.4 if
UFLS program deficiencies are identified in D.B.11.

Page 28 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#
D.B.1

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical
events, to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical events
and system studies, to select
portions of the BES, including
interconnected portions of the
BES in adjacent Planning
Coordinator areas, that may form
islands

OR

Severe VSL
The Planning Coordinator failed
to participate in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of system studies,
to select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands
Page 29 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#
D.B.2

Lower VSL

Moderate VSL

High VSL

N/A
N/A

The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include one
(1) of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2

Severe VSL
The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include all
of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2
OR
The Planning Coordinator failed
to identify any island(s) from the
regional review to serve as a
basis for designing its UFLS
program.

D.B.3

N/A

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, or D.B.3.3 in

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that included
notification of and a schedule for
implementation by UFLS entities
within its area, but failed to meet
two (2) of the performance
characteristic in Requirement
D.B.3, Parts D.B.3.1, D.B.3.2, or
D.B.3.3 in simulations of
underfrequency conditions

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, and D.B.3.3 in

Page 30 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

simulations of underfrequency
conditions

Severe VSL
simulations of underfrequency
conditions
OR
The Planning Coordinator failed
to adopt a UFLS program,
coordinated across the WECC
Regional Entity area, including
notification of and a schedule for
implementation by UFLS entities
within its area.

D.B.4

The Planning Coordinator
participated in and
documented a coordinated
UFLS assessment with the other
Planning Coordinators in the
WECC Regional Entity area at
least once every five years that
determines through dynamic
simulation whether the UFLS
program design meets the
performance characteristics in
Requirement D.B.3 for each
island identified in Requirement
D.B.2 but the simulation failed
to include one (1) of the items
as specified in Requirement

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include two
(2) of the items as specified in
Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include three
(3) of the items as specified in
Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include four
(4) or more of the items as
specified in Requirement D.B.4,
Parts D.B.4.1 through D.B.4.7.
Page 31 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

D.B.4, Parts D.B.4.1 through
D.B.4.7.

D.B.11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below the
initializing set points of the
UFLS program, participated in
and documented a coordinated
event assessment with all
Planning Coordinators whose
areas or portions of whose
areas were also included in the
same islanding event and
evaluated the parts as specified

Severe VSL
OR
The Planning Coordinator failed
to participate in and document a
coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
Page 32 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than one year but
less than or equal to 13 months
of actuation.

D.B.11.1 and D.B.11.2 within a
time greater than 13 months but
less than or equal to 14 months
of actuation.

D.B.11.1 and D.B.11.2 within a
time greater than 14 months but
less than or equal to 15 months
of actuation.

D.B.11.1 and D.B.11.2 within a
time greater than 15 months of
actuation.

OR

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to participate in and
document a coordinated event
assessment with all Planning
Coordinators whose areas or
portion of whose areas were also
included in the same island event
and evaluate the parts as
specified in Requirement D.B.11,
Parts D.B.11.1 and D.B.11.2.

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event
within one year of event
actuation but failed to evaluate
one (1) of the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 or D.B.11.2.

Severe VSL

OR

OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
Page 33 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
whose areas or portions of
whose areas were also included
in the same islanding event
within one year of event
actuation but failed to evaluate
all of the parts as specified in
Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2.

D.B.12

N/A

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than two
years but less than or equal to 25
months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 25
months but less than or equal to
26 months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 26
months of event actuation.
OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, failed to participate in
and document a coordinated
UFLS design assessment of the
Page 34 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies

Page 35 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
E. Associated Documents
Version History
Version
0

Date
April 1, 2005

Action
Effective Date

1

May 25, 2010

Completed revision, merging and
updating PRC-006-0, PRC-007-0 and
PRC-009-0.

1

November 4, 2010

Adopted by the Board of Trustees

1

May 7, 2012

FERC Order issued approving PRC006-1 (approval becomes effective
July 10, 2012)

1

November 9, 2012

2

November 13, 2014

FERC Letter Order issued accepting
the modification of the VRF in R5
from (Medium to High) and the
modification of the VSL language in
R8.
Adopted by the Board of Trustees

Change Tracking
New

Revisions made under
Project 2008-02:
Undervoltage Load
Shedding (UVLS) &
Underfrequency Load
Shedding (UFLS) to address
directive issued in FERC
Order No. 763.
Revisions to existing
Requirement R9 and
R10 and addition of
new Requirement
R15.

3
4

August 10, 2017

Adopted by the NERC Board of
Trustees
Adopted by the NERC Board of
Trustees

Revisions to the Regional
Variance for the Quebec
Interconnection.

Page 36 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

PRC-006-3 – Attachment 1
Underfrequency Load Shedding Program
Design Performance and Modeling Curves for
Requirements R3 Parts 3.1-3.2 and R4 Parts 4.1-4.6
63

Overfrequency Trip Settings
Must Be Modeled for Generators
That Trip Below the Generator
Overfrequency Trip Modeling
Curve

62

Simulated Frequency Must
Remain Between the
Overfrequency and
Underfrequency Performance
Characteristic Curves

60

59

58

Underfrequency Trip Settings
Must Be Modeled for Generators
That Trip Above the Generator
Underfrequency Trip Modeling
Curve

57
1

0.1

Time (sec)

10

100

Generator Overfrequency Trip Modeling (Requirement R4 Parts 4.4-4.6)
Overfrequency Performance Characteristic (Requirement R3 Part 3.2)
Underfrequency Performance Characteristic (Requirement R3 Part 3.1)
Generator Underfrequency Trip Modeling (Requirement R4 Parts 4.1-4.3)

Curve Definitions
Generator Overfrequency Trip Modeling

Overfrequency Performance Characteristic

t≤2s

t≤4s

t>2s

4 s < t ≤ 30 s

t > 30 s

Page 37 of 40

Frequency (Hz)

61

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
f = 62.2
Hz

f = -0.686log(t) + 62.41
Hz

f = 61.8
Hz

f = -0.686log(t) + 62.21
Hz

f = 60.7
Hz

Generator Underfrequency Trip
Modeling

Underfrequency Performance Characteristic

t≤2s

t>2s

t≤2s

2 s < t ≤ 60 s

t > 60 s

f = 57.8
Hz

f = 0.575log(t) + 57.63
Hz

f = 58.0
Hz

f = 0.575log(t) + 57.83
Hz

f = 59.3
Hz

Page 38 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

Page 39 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

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 R9:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a Planning Coordinator (PC)
assessment. The revised language adds clarity by requiring that each UFLS entity follow the
UFLS program, including any Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R10:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a PC assessment. The revised
language adds clarity by requiring that each UFLS entity follow the UFLS program, including any
Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R15:
Requirement R15 was added in response to the directive from FERC Order No. 763, which
raised concern that the standard failed to specify how soon an entity would need to implement
corrections after a deficiency is identified by a PC assessment. Requirement R15 addresses the
FERC directive by making explicit that if deficiencies are identified as a result of an assessment,
the PC shall develop a Corrective Action Plan and schedule for implementation by the UFLS
entities.
A “Corrective Action Plan” is defined in the NERC Glossary of Terms as, “a list of actions and an
associated timetable for implementation to remedy a specific problem.” Thus, the Corrective
Action Plan developed by the PC will identify the specific timeframe for an entity to implement
corrections to remedy any deficiencies identified by the PC as a result of an assessment.

Page 40 of 40

TOP-003-4 — Operational Reliability Data

A. Introduction
1.

Title: Operational Reliability Data

2.

Number: TOP-003-4

3.

Purpose: To ensure that the Transmission Operator and Balancing Authority have
data needed to fulfill their operational and planning responsibilities.

4.

Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Generator Owner
4.4. Generator Operator
4.5. Transmission Owner
4.6. Distribution Provider

5.

Effective Date:
See Implementation Plan.

B. Requirements and Measures
R1. Each Transmission Operator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include, but not be limited to:
[Violation Risk Factor: Low] [Time Horizon: Operations Planning]
1.1.

A list of data and information needed by the Transmission Operator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data as
deemed necessary by the Transmission Operator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

M1. Each Transmission Operator shall make available its dated, current, in force
documented specification for data.
R2.

Each Balancing Authority shall maintain a documented specification for the data
necessary for it to perform its analysis functions and Real-time monitoring. The data
specification shall include, but not be limited to: [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]

Draft 1 of TOP-003-4
October 2019

Page 1 of 10

TOP-003-4 — Operational Reliability Data

2.1.

A list of data and information needed by the Balancing Authority to support
its analysis functions and Real-time monitoring.

2.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

2.3.

A periodicity for providing data.

2.4.

The deadline by which the respondent is to provide the indicated data.

M2. Each Balancing Authority shall make available its dated, current, in force documented
specification for data.
R3. Each Transmission Operator shall distribute its data specification to entities that have
data required by the Transmission Operator’s Operational Planning Analyses, Realtime monitoring, and Real-time Assessment. [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]
M3. Each Transmission Operator shall make available evidence that it has distributed its
data specification to entities that have data required by the Transmission Operator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments.
Such evidence could include but is not limited to web postings with an electronic
notice of the posting, dated operator logs, voice recordings, postal receipts showing
the recipient, date and contents, or e-mail records.
R4. Each Balancing Authority shall distribute its data specification to entities that have
data required by the Balancing Authority’s analysis functions and Real-time
monitoring. [Violation Risk Factor: Low] [Time Horizon: Operations Planning]
M4. Each Balancing Authority shall make available evidence that it has distributed its data
specification to entities that have data required by the Balancing Authority’s analysis
functions and Real-time monitoring. Such evidence could include but is not limited to
web postings with an electronic notice of the posting, dated operator logs, voice
recordings, postal receipts showing the recipient, or e-mail records.
R5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Owner, and Distribution Provider receiving a data
specification in Requirement R3 or R4 shall satisfy the obligations of the documented
specifications using: [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning, Same-Day Operations, Real-time Operations]
5.1. A mutually agreeable format
5.2. A mutually agreeable process for resolving data conflicts
5.3. A mutually agreeable security protocol
M5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Owner, and Distribution Provider receiving a data specification
in Requirement R3 or R4 shall make available evidence that it has satisfied the
obligations of the documented specifications. Such evidence could include, but is not
Draft 1 of TOP-003-4
October 2019

Page 2 of 10

TOP-003-4 — Operational Reliability Data

limited to, electronic or hard copies of data transmittals or attestations of receiving
entities.
C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Process
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Assessment Processes
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated reliability standard.
1.3. Data 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 responsible entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
Each Transmission Operator shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments in accordance with
Requirement R1 and Measurement M1 as well as any documents in force since
the last compliance audit.
Each Balancing Authority shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its analysis functions and
Real-time monitoring in accordance with Requirement R2 and Measurement M2
as well as any documents in force since the last compliance audit.
Each Transmission Operator shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the
Transmission Operator’s Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments in accordance with Requirement R3 and
Measurement M3.

Draft 1 of TOP-003-4
October 2019

Page 3 of 10

TOP-003-4 — Operational Reliability Data

Each Balancing Authority shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the
Balancing Authority’s analysis functions and Real-time monitoring in accordance
with Requirement R4 and Measurement M4.
Each Balancing Authority, Generator Owner, Generator Operator, Transmission
Operator, Transmission Owner, and Distribution Provider receiving a data
specification in Requirement R3 or R4 shall retain evidence for the most recent
90-calendar days that it has satisfied the obligations of the documented
specifications in accordance with Requirement R5 and Measurement M5.
If a responsible entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved or the time
period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.

Draft 1 of TOP-003-4
October 2019

Page 4 of 10

TOP-003-4 — Operational Reliability Data

Table of Compliance Elements
R#

R1

Time Horizon

Operations
Planning

Draft 1 of TOP-003-4
October 2019

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Transmission
Operator did not
include one of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include three of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include four of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.
OR,
The Transmission
Operator did not have
a documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

Page 5 of 10

TOP-003-4 — Operational Reliability Data

R#

R2

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Balancing
Authority did not
include one of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include two of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include three of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include four of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.
OR,
The Balancing
Authority did not
have a documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

For the Requirement R3 and R4 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to
the left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity
has just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R3

Operations
Planning

Draft 1 of TOP-003-4
October 2019

Low

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

Page 6 of 10

TOP-003-4 — Operational Reliability Data

R#

R4

Time Horizon

Operations
Planning

Draft 1 of TOP-003-4
October 2019

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to two
entities, or more than
5% and less than or
equal to10% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to three
entities, or more than
10% and less than or
equal to 15% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Balancing
Authority did not
distribute its data
specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to two
entities, or more than
5% and less than or
equal to 10% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to three
entities, or more than
10% and less than or
equal to 15% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

Page 7 of 10

TOP-003-4 — Operational Reliability Data

R#

R5

Time Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

Draft 1 of TOP-003-4
October 2019

Violation Severity Levels

VRF

Medium

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible
entity receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet one of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet two of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet three of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
did not satisfy the
obligations of the
documented
specifications for
data.

Page 8 of 10

TOP-003-4 — Guidelines and Technical Basis

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

0

April 1, 2005

0

August 8, 2005

Action

Effective Date
Removed “Proposed” from Effective
Date
Modified R1.2
Modified M1

1

Change Tracking

New
Errata
Revised

Replaced Levels of Non-compliance
with the Feb 28, BOT approved
Violation Severity Levels (VSLs)
1

October 17, 2008

Adopted by NERC Board of Trustees

1

March 17, 2011

Order issued by FERC approving TOP003-1 (approval effective 5/23/11)

2

May 6, 2012

Revised under Project 2007-03

Revised

2

May 9, 2012

Adopted by Board of Trustees

Revised

3

April 2014

Changes pursuant to Project 2014-03

Revised

3

November 13, 2014 Adopted by Board of Trustees

3

November 19, 2015 FERC approved TOP-003-3. Docket No.
RM15-16-000, Order No. 817
Adopted by Board of Trustees

4

Draft 1 of TOP-003-4
October 2019

Revisions under
Project 2014-03

Page 9 of 10

TOP-003-4 — Guidelines and Technical Basis

Guidelines and Technical Basis
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 Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to
result in an appropriate level of situational awareness. Some examples include: 1) analyzing
phase angles which may result in the implementation of an Operating Plan to adjust generation
or curtail transactions so that a Transmission facility may be returned to service, or 2)
evaluating the impact of a modified Contingency resulting from the status change of a Special
Protection Scheme from enabled/in-service to disabled/out-of-service.
Rationale for R1:
Changes to proposed Requirement R1, Part 1.1 are in response to issues raised in NOPR
paragraph 67 on the need for obtaining non-BES and external network data necessary for the
Transmission Operator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2 is in response to NOPR paragraph 78 on relay data. The
language has been moved from approved PRC-001-1.
Corresponding changes have been made to Requirement R2 for the Balancing Authority and to
proposed IRO-010-2, Requirement R1 for the Reliability Coordinator.
Rationale for R5:
Proposed Requirement R5, Part 5.3 is in response to NOPR paragraph 92 where concerns were
raised about data exchange through secured networks.

Draft 1 of TOP-003-4
October 2019

Page 10 of 10

Standard TOP-003-3 4 — Operational Reliability Data
A. Introduction
1.

Title: Operational Reliability Data

2.

Number: TOP-003-43

3.

Purpose: To ensure that the Transmission Operator and Balancing Authority have
data needed to fulfill their operational and planning responsibilities.

4.

Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Generator Owner
4.4. Generator Operator
4.5. Load-Serving Entity

5.

4.6.4.5.

Transmission Owner

4.7.4.6.

Distribution Provider

Effective Date:
See Implementation Plan.

6.

Background:
See Project 2014-03 project page.

B. Requirements and Measures
R1. Each Transmission Operator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include, but not be limited to:
[Violation Risk Factor: Low] [Time Horizon: Operations Planning]
1.1.

A list of data and information needed by the Transmission Operator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data as
deemed necessary by the Transmission Operator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

M1. Each Transmission Operator shall make available its dated, current, in force
documented specification for data.

Page 1 of 10

Standard TOP-003-3 4 — Operational Reliability Data
R2.

Each Balancing Authority shall maintain a documented specification for the data
necessary for it to perform its analysis functions and Real-time monitoring. The data
specification shall include, but not be limited to: [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]
2.1.

A list of data and information needed by the Balancing Authority to support
its analysis functions and Real-time monitoring.

2.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

2.3.

A periodicity for providing data.

2.4.

The deadline by which the respondent is to provide the indicated data.

M2. Each Balancing Authority shall make available its dated, current, in force documented
specification for data.
R3. Each Transmission Operator shall distribute its data specification to entities that have
data required by the Transmission Operator’s Operational Planning Analyses, Realtime monitoring, and Real-time Assessment. [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]
M3. Each Transmission Operator shall make available evidence that it has distributed its
data specification to entities that have data required by the Transmission Operator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments.
Such evidence could include but is not limited to web postings with an electronic
notice of the posting, dated operator logs, voice recordings, postal receipts showing
the recipient, date and contents, or e-mail records.
R4. Each Balancing Authority shall distribute its data specification to entities that have
data required by the Balancing Authority’s analysis functions and Real-time
monitoring. [Violation Risk Factor: Low] [Time Horizon: Operations Planning]
M4. Each Balancing Authority shall make available evidence that it has distributed its data
specification to entities that have data required by the Balancing Authority’s analysis
functions and Real-time monitoring. Such evidence could include but is not limited to
web postings with an electronic notice of the posting, dated operator logs, voice
recordings, postal receipts showing the recipient, or e-mail records.
R5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R3 or R4 shall satisfy the obligations of
the documented specifications using: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning, Same-Day Operations, Real-time Operations]
5.1. A mutually agreeable format
5.2. A mutually agreeable process for resolving data conflicts
5.3. A mutually agreeable security protocol

Page 2 of 10

Standard TOP-003-3 4 — Operational Reliability Data
M5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R3 or R4 shall make available evidence
that it has satisfied the obligations of the documented specifications. Such evidence
could include, but is not limited to, electronic or hard copies of data transmittals or
attestations of receiving entities.
C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Process
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Assessment Processes
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated reliability standard.
1.3. Data 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 responsible entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
Each Transmission Operator shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments in accordance with
Requirement R1 and Measurement M1 as well as any documents in force since
the last compliance audit.
Each Balancing Authority shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its analysis functions and
Real-time monitoring in accordance with Requirement R2 and Measurement M2
as well as any documents in force since the last compliance audit.
Each Transmission Operator shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the

Page 3 of 10

Standard TOP-003-3 4 — Operational Reliability Data
Transmission Operator’s Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments in accordance with Requirement R3 and
Measurement M3.
Each Balancing Authority shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the
Balancing Authority’s analysis functions and Real-time monitoring in accordance
with Requirement R4 and Measurement M4.
Each Balancing Authority, Generator Owner, Generator Operator, Load-Serving
Entity, Transmission Operator, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R3 or R4 shall retain evidence for
the most recent 90-calendar days that it has satisfied the obligations of the
documented specifications in accordance with Requirement R5 and
Measurement M5.
If a responsible entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved or the time
period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.

Page 4 of 10

Standard TOP-003-3 4 — Operational Reliability Data
Table of Compliance Elements
R#

R1

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Transmission
Operator did not
include one of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include three of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include four of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.
OR,
The Transmission
Operator did not have
a documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

Page 5 of 10

Standard TOP-003-3 4 — Operational Reliability Data
R#

R2

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Balancing
Authority did not
include one of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include two of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include three of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include four of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.
OR,
The Balancing
Authority did not
have a documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

For the Requirement R3 and R4 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to
the left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity
has just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R3

Operations
Planning

Low

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

Page 6 of 10

Standard TOP-003-3 4 — Operational Reliability Data
R#

R4

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to two
entities, or more than
5% and less than or
equal to10% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to three
entities, or more than
10% and less than or
equal to 15% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Balancing
Authority did not
distribute its data
specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to two
entities, or more than
5% and less than or
equal to 10% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to three
entities, or more than
10% and less than or
equal to 15% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

Page 7 of 10

Standard TOP-003-3 4 — Operational Reliability Data
R#

R5

Time Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

Violation Severity Levels

VRF

Medium

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible
entity receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet one of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet two of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet three of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
did not satisfy the
obligations of the
documented
specifications for
data.

Page 8 of 10

Standard TOP-003-3 4 — Guidelines and Technical Basis
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

0

April 1, 2005

0

August 8, 2005

Action
Effective Date
Removed “Proposed” from Effective
Date
Modified R1.2
Modified M1

1

Change Tracking
New
Errata
Revised

Replaced Levels of Non-compliance
with the Feb 28, BOT approved
Violation Severity Levels (VSLs)
1

October 17, 2008

Adopted by NERC Board of Trustees

1

March 17, 2011

Order issued by FERC approving TOP003-1 (approval effective 5/23/11)

2

May 6, 2012

Revised under Project 2007-03

Revised

2

May 9, 2012

Adopted by Board of Trustees

Revised

3

April 2014

Changes pursuant to Project 2014-03

Revised

3

November 13, 2014 Adopted by Board of Trustees

3

November 19, 2015 FERC approved TOP-003-3. Docket No.
RM15-16-000, Order No. 817
Adopted by Board of Trustees

4

Revisions under
Project 2014-03

Page 9 of 10

Standard TOP-003-3 4 — Guidelines and Technical Basis
Guidelines and Technical Basis
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 Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to
result in an appropriate level of situational awareness. Some examples include: 1) analyzing
phase angles which may result in the implementation of an Operating Plan to adjust generation
or curtail transactions so that a Transmission facility may be returned to service, or 2)
evaluating the impact of a modified Contingency resulting from the status change of a Special
Protection Scheme from enabled/in-service to disabled/out-of-service.
Rationale for R1:
Changes to proposed Requirement R1, Part 1.1 are in response to issues raised in NOPR
paragraph 67 on the need for obtaining non-BES and external network data necessary for the
Transmission Operator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2 is in response to NOPR paragraph 78 on relay data. The
language has been moved from approved PRC-001-1.
Corresponding changes have been made to Requirement R2 for the Balancing Authority and to
proposed IRO-010-2, Requirement R1 for the Reliability Coordinator.
Rationale for R5:
Proposed Requirement R5, Part 5.3 is in response to NOPR paragraph 92 where concerns were
raised about data exchange through secured networks.

Page 10 of 10

Implementation Plan

Project 2017-07 Standards Alignment with Registration
Applicable Standards
•

FAC-002-3 – Facility Interconnection Studies

•

IRO-010-3 – Reliability Coordinator Data Specification and Collection

•

MOD-031-3 – Demand and Energy Data

•

MOD-033-2 – Steady-State and Dynamic System Model Validation

•

NUC-001-4 – Nuclear Plant Interface Coordination

•

PRC-006-4 – Automatic Underfrequency Load Shedding

•

TOP-003-4 – Operational Reliability Data

Requested Retirements
•

FAC-002-2 – Facility Interconnection Studies

•

IRO-010-2 – Reliability Coordinator Data Specification and Collection

•

MOD-031-2 – Demand and Energy Data

•

MOD-033-1 – Steady-State and Dynamic System Model Validation

•

NUC-001-3 – Nuclear Plant Interface Coordination

•

PRC-006-3 – Automatic Underfrequency Load Shedding

•

TOP-003-3 – Operational Reliability Data

Applicable Entities
See subject standards.
Background
On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North
American Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) initiative in Docket
No. RR15-4-000. FERC approved the removal of two functional categories, Purchasing-Selling Entity
(PSE) and Interchange Authority (IA), from the NERC Compliance Registry due to the commercial
nature of these categories posing little or no risk to the reliability of the bulk power system. FERC
also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently approved
on compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria.

RELIABILITY | RESILIENCE | SECURITY

Several projects have addressed standards impacted by the RBR initiative since FERC approval;
however, there remain some Reliability Standards that require minor revisions so that they align
with the post-RBR registration impacts.
Project 2017-07 Standards Alignment with Registration formally addressed the remaining edits to
the Reliability Standards that are needed to align the existing standards with the RBR
initiatives. The edits include updates to the FAC, IRO, MOD, NUC, and TOP family of standards.
References to Load-Serving Entity (LSEs) were removed or replaced by the appropriate NERC
Registered Entity. PRC-006 was updated to replace Distribution Providers (DP) with the morelimited UFLS-only DP to the Applicability Section. A majority of the edits simply removed
deregistered functional entities and their applicable requirements/references.
Effective Date
Reliability Standards FAC-002-3, IRO-010-3, MOD-031-3, MOD-033-2, NUC-001-4, PRC-006-4, and TOP003-4
Where approval by an applicable governmental authority is required, the standard shall become
effective on the first day of the first calendar quarter that is three (3) months after the effective date of
the applicable governmental authority’s order approving the standard, or as otherwise provided for by
the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is three (3) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Retirement Date
Reliability Standards FAC-002-2, IRO-010-2, MOD-031-2, MOD-033-1, NUC-001-3, PRC-006-

3, and TOP-003-3

The Reliability Standard shall be retired immediately prior to the effective date of the revised standard
in the particular jurisdiction in which the revised standard is becoming effective.

Implementation Plan
Project 2017-07 Standards Alignment with Registration | October 2019

2

Unofficial Comment Form

Project 2017-07 Standards Alignment with Registration
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on Project 2017-07 Standards Alignment with Registration by 8 p.m. Eastern,
December 12, 2019.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact NERC Standards
Developer, Laura Anderson (via email), or at 404-446-9671.
Background Information

Project 2017-07 addresses Reliability Standards impacted by the Risk Based Registration (RBR) initiative
approved by the Federal Energy Regulatory Commission (FERC) in Docket No. RR15-4-000. Some
Reliability Standards require edits to align existing standards with the RBR. The standard drafting team
(SDT) reviewed standards from the BAL, CIP, FAC, INT, IRO, MOD, NUC, and TOP family of standards to
remove the references to the retired functions Purchasing-Selling Entity (PSE) and Interchange Authority
(IA), and update references to the Load-Serving Entity (LSE) by either removing or replacing with an
appropriate Registered Entity (e.g., MOD-032-1). Additionally, the SDT considered adding Underfrequency
Load Shedding (UFLS)-Only Distribution Provider (UFLS-Only Distribution Provider) to the Applicability
section of PRC-005 and PRC-006 per NERC registration criteria, and whether to include a definition for
“UFLS-Only Distribution Provider” into the NERC Glossary of Terms; as well as review the standards to
ensure consistent use of the term Planning Coordinator.
The following Reliability Standards have been identified for revision:
•

FAC-002-2 is being revised to remove references to Load-Serving Entity.

•

IRO-010-2 is being revised to remove references to Load-Serving Entity.

•

MOD-031-2 and MOD-033-1 are being revised to change Planning Authority to Planning
Coordinator.

•

NUC-001-3 is being revised to remove references to Load-Serving Entity. Note: only NUC-001-3 R1
has been recommended for retirement by Standard Efficiency Review Phase 1.

•

PRC-006 is being revised to add “UFLS Only- Distribution Provider” to the Applicability section.

•

TOP-003-3 is being revised to remove references to Load-Serving Entity.

RELIABILITY | RESILIENCE | SECURITY

The following Reliability Standards were reviewed but are not being proposed for modification due to the
following reasons:
•

BAL-005-0.2b has been superseded by BAL-005-1 on January 1, 2019, which deleted the LoadServing Entity function).

•

CIP-002-5.1a, CIP-003-6, CIP-003-7, CIP-004-6, CIP-005-5, CIP-005-6, CIP-006-6, CIP-007-6, CIP-0085, CIP-009-6, CIP-010-2, and CIP-011-2 will not be revised at this time due to the current Project
2016-02 (Modifications to CIP Standards) and the CIP Standards Efficiency Review.

•

FAC-010-3, FAC-011-3, and FAC-014-2 are being addressed in Project 2015-09.

•

INT-004-3.1 and INT-006-4 are recommended for retirement by Standard Efficiency Review Phase
1.

•

MOD-001-2, MOD-004-1, MOD-020-0 are recommended for retirement by Standard Efficiency
Review Phase 1.

•

MOD-032-1 will not be revised at this time due to the work of the System Planning Impact from
Distributed Energy Resource Working Group (SPIDERWG). In June 2018, the NERC Planning
Committee (PC) formed the SPDERWG subcommittee to address Distributed Energy Resource
(DER) impacts on the bulk power system (BPS). Currently, the subcommittee has proposed a
Standard Authorization Request (SAR) for MOD-032-1 pertaining to DERs. The SAR is currently
under the PC review. At this time, the Project 2017-07 drafting team will not take any action in
reference to the MOD-032 standard until the SPIDERWG has completed their initial efforts.

•

PRC-005-6 will not be revised at this time due to the current Project 2019-04 (Modifications to
PRC-005-6).

Unofficial Comment Form
Project 2017-07 Standards Alignment with Registration | October 2019

2

Questions

1. The SDT approach is to align the FAC-002-2 standard with the RBR initiative by removing
references to retired functions. Do you agree with the proposed changes to the standard? If you
disagree, please explain and provide alternative language that will support the RBR initiative.
Yes
No
Comments:
2. The SDT approach is to align the IRO-010-2 standard with the RBR initiative by removing
references to retired functions. Do you agree with the proposed changes to the standard? If you
disagree, please explain and provide alternative language that will support the RBR initiative.
Yes
No
Comments:
3. The SDT approach is to align the MOD-031-2 and MOD-033-1 standards with the RBR initiative by
changing “Planning Authority” to “Planning Coordinator.” Do you agree with the proposed
changes to the standard? If you disagree, please explain and provide alternative language that will
support the RBR initiative.
Yes
No
Comments:

Unofficial Comment Form
Project 2017-07 Standards Alignment with Registration | October 2019

3

4. The SDT approach is to align the NUC-001-3 standard with the RBR initiative by removing
references to retired functions. Do you agree with the proposed changes to the standard? If you
disagree, please explain and provide alternative language that will support the RBR initiative.
Yes
No
Comments:
5. The SDT approach is to align the PRC-006-3 standard with the RBR initiative and the standard is
being revised to add “UFLS Only- Distribution Provider” consistent with NERC registration criteria.
Do you agree with the proposed changes to the standard? If you disagree, please explain and
provide alternative language that will support the RBR initiative.
Yes
No
Comments:
6. The SDT approach is to align the TOP-003-3 standard with the RBR initiative by removing
references to retired functions. Do you agree with the proposed changes to the standard? If you
disagree, please explain and provide alternative language that will support the RBR initiative.
Yes
No
Comments:
7. Please provide any additional comments for the SDT to consider that you have not already
provided for Project 2017-07.
Comments:

Unofficial Comment Form
Project 2017-07 Standards Alignment with Registration | October 2019

4

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, FAC-002-3. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for FAC-002-3, Requirement R1
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R1
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF Justification for FAC-002-3, Requirement R2
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R2
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF Justification for FAC-002-3, Requirement R3
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R3
This justification is provided on the following page.
VRF Justification for FAC-002-3, Requirement R4
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R4
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF Justification for FAC-002-3, Requirement R5
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R5
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

5

VSLs for FAC-002-3, Requirement R3

Lower

Moderate

High

Severe

The Transmission Owner or
Distribution Provider seeking to
interconnect new transmission
Facilities or electricity end-user
Facilities, or to materially modify
existing interconnections of
transmission Facilities or
electricity end-user Facilities,
coordinated and cooperated on
studies with its Transmission
Planner or Planning Coordinator,
but failed to provide data
necessary to perform studies as
described in one of the Parts
(R1, 1.1-1.4).

The Transmission Owner, or
Distribution Provider Entity
seeking to interconnect new
transmission Facilities or
electricity end-user Facilities, or
to materially modify existing
interconnections of transmission
Facilities or electricity end-user
Facilities, coordinated and
cooperated on studies with its
Transmission Planner or
Planning Coordinator, but failed
to provide data necessary to
perform studies as described in
two of the Parts (R1, 1.1-1.4).

The Transmission Owner or
Distribution Provider Entity
seeking to interconnect new
transmission Facilities or
electricity end-user Facilities, or
to materially modify existing
interconnections of transmission
Facilities or electricity end-user
Facilities, coordinated and
cooperated on studies with its
Transmission Planner or
Planning Coordinator, but failed
to provide data necessary to
perform studies as described in
three of the Parts (R1, 1.1-1.4).

The Transmission Owner, or
Distribution Provider Entity
seeking to interconnect new
transmission Facilities or
electricity end-user Facilities, or
to materially modify existing
interconnections of transmission
Facilities or electricity end-user
Facilities, failed to coordinate
and cooperate on studies with
its Transmission Planner or
Planning Coordinator.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

6

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, IRO-010-3. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for IRO-010-3, Requirement R1
The VRF did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VSL Justification for IRO-010-3, Requirement R1
The VSL did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VRF Justification for IRO-010-3, Requirement R2
The VRF did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VSL Justification for IRO-010-3, Requirement R2
The VSL did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VRF Justification for IRO-010-3, Requirement R3
The VRF did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VSL Justification for IRO-010-3, Requirement R3
The VSL did not change from the previously FERC approved IRO-010-2 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

5

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, MOD-031-3. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for MOD-031-3, Requirement R1
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R1
The VSL did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VRF Justification for MOD-031-3, Requirement R2
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R2
The VSL did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VRF Justification for MOD-031-3, Requirement R3
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R3
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VRF Justification for MOD-031-3, Requirement R4
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R4
The VSL did not change from the previously FERC approved MOD-031-2 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

5

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, MOD-033-2. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for MOD-033-2, Requirement R1
The VRF did not change from the previously FERC approved MOD-033-1 Reliability Standard.
VSL Justification for F MOD-033-2, Requirement R1
The VSL did not change from the previously FERC approved MOD-033-1 Reliability Standard.
VRF Justification for MOD-033-2, Requirement R2
The VRF did not change from the previously FERC approved MOD-033-1 Reliability Standard.
VSL Justification for MOD-033-2, Requirement R2
The VSL did not change from the previously FERC approved MOD-033-1 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

5

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, NUC-001-4. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for NUC-001-4, Requirement R1
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R1
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R2
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R2
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R3
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R3
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R4
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R4
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R5
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R5
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

5

VRF Justification for NUC-001-4, Requirement R6
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R6
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R7
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R7
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R8
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R8
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R9
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R9
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

6

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, PRC-006-4. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for PRC-006-4, Requirement R1
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R1
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R2
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R2
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R3
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R3
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R4
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R4
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R5
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R5
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

5

VRF Justification for PRC-006-4, Requirement R6
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R6
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R7
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R7
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R8
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R8
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R9
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R9
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R10
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R10
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R11
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

6

VSL Justification for PRC-006-4, Requirement R11
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R12
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R12
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R13
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R13
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R14
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R14
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R15
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R15
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

7

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, TOP-003-4. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for TOP-003-4, Requirement R1
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R1
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R2
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R2
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R3
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R3
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R4
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R4
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R5
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R5
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | October 2019

5

Standards Announcement

Project 2017-07 Standards Alignment with Registration
Formal Comment Period Open through December 12, 2019
Ballot Pools Forming through November 27, 2019
Now Available

A 45-day formal comment period for Project 2017-07 Standards Alignment with Registration is open
through 8 p.m. Eastern, Thursday, December 12, 2019 for the following Standards and Implementation
Plan:
•

FAC-002-3 – Facility Interconnection Studies

•

IRO-010-3 – Reliability Coordinator Data Specification and Collection

•

MOD-031-3 – Demand and Energy Data

•

MOD-033-2 – Steady-State and Dynamic System Model Validation

•

NUC-001-4 – Nuclear Plant Interface Coordination

•

PRC-006-4 – Automatic Underfrequency Load Shedding

•

TOP-003-4 – Operational Reliability Data

•

Implementation Plan

Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience
issues navigating the SBS, contact Linda Jenkins. An unofficial Word version of the comment form is
posted on the project page.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours
for NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging
into their SBS accounts prior to the last day of a comment/ballot period.

RELIABILITY | RESILIENCE | SECURITY

Next Steps

Initial ballots for the Standards and Implementation Plan, along with non-binding polls for each
associated Violation Risk Factors and Violation Severity Levels, will be conducted December 3-12,
2019.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Laura Anderson (via email) or at
(404) 446-9671.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2017-07 Standards Alignment with Registration
Initial Ballot | October 2019

2

Comment Report
Project Name:

Project 2017-07 Standards Alignment with Registeation

Comment Period Start Date:

10/29/2019

Comment Period End Date:

12/12/2019

Associated Ballots:

2017-07 Standards Alignment with Registration FAC-002-3 IN 1 ST
2017-07 Standards Alignment with Registration Implementation Plan IN 1 OT
2017-07 Standards Alignment with Registration IRO-010-3 IN 1 ST
2017-07 Standards Alignment with Registration MOD-031-3 IN 1 ST
2017-07 Standards Alignment with Registration MOD-033-2 IN 1 ST
2017-07 Standards Alignment with Registration NUC-001-4 IN 1 ST
2017-07 Standards Alignment with Registration PRC-006-4 IN 1 ST
2017-07 Standards Alignment with Registration TOP-003-4 IN 1 ST

There were 32 sets of responses, including comments from approximately 75 different people from approximately 61 companies
representing 10 of the Industry Segments as shown in the table on the following pages.

Questions
1. The SDT approach is to align the FAC-002-2 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.

2. The SDT approach is to align the IRO-010-2 standard with the RBR initiative by removing references to retired functions. Do you agree with
the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR initiative.

3. The SDT approach is to align the MOD-031-2 and MOD-033-1 standards with the RBR initiative by changing “Planning Authority” to
“Planning Coordinator.” Do you agree with the proposed changes to the standard? If you disagree, please explain and provide alternative
language that will support the RBR initiative.

4, The SDT approach is to align the NUC-001-3 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.

5. The SDT approach is to align the PRC-006-3 standard with the RBR initiative and the standard is being revised to add “UFLS OnlyDistribution Provider” consistent with NERC registration criteria. Do you agree with the proposed changes to the standard? If you disagree,
please explain and provide alternative language that will support the RBR initiative.

6. The SDT approach is to align the TOP-003-3 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.

7. Please provide any additional comments for the SDT to consider that you have not already provided for Project 2017-07.

Organization
Name

Name

Douglas
Webb

Douglas Webb

Southern
Company Alabama
Power
Company

Joel
Dembowski

DTE Energy - Karie Barczak
Detroit Edison
Company

Duke Energy

Northeast
Power
Coordinating
Council

Kim Thomas

Ruida Shu

Segment(s)

Region

MRO,SPP RE

3

Group
Member
Organization

Westar-KCPL Doug Webb

Westar

1,3,5,6

MRO

Doug Webb

KCP&L

1,3,5,6

MRO

Adrianne Collins

Southern
1
Company
Services, Inc.

SERC

Bill Shultz

Southern
Company
Generation

5

SERC

Ron Carlsen

Southern
Company
Generation
and Energy
Marketing

6

SERC

Joel Dembowski

Alabama
Power
Company

3

SERC

Southern
Company

3,4,5

1,3,5,6

Group Name Group Member
Name

DTE Energy - Jeffrey Depriest
DTE Electric

RSC

Group Member
Region

DTE Energy - 5
DTE Electric

RF

Daniel Herring

DTE Energy - 4
DTE Electric

RF

Karie Barczak

DTE Energy - 3
DTE Electric

RF

Duke Energy

1

SERC

Dale Goodwine

Duke Energy

5

SERC

Greg Cecil

Duke Energy

6

RF

Guy V. Zito

Northeast
Power
Coordinating
Council

10

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian Robinson

Utility
Services

5

NPCC

Alan Adamson

New York
State
Reliability
Council

7

NPCC

FRCC,RF,SERC Duke Energy Laura Lee

1,2,3,4,5,6,7,8,9,10 NPCC

Group
Member
Segment(s)

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele Tondalo UI

1

NPCC

Helen Lainis

IESO

2

NPCC

Sean Cavote

PSEG

4

NPCC

Kathleen
Goodman

ISO-NE

2

NPCC

David Kiguel

Independent

NA - Not
Applicable

NPCC

Silvia Mitchell

NextEra
6
Energy Florida Power
and Light Co.

NPCC

Paul Malozewski Hydro One
3
Networks, Inc.

NPCC

Nick Kowalczyk

Orange and
Rockland

1

NPCC

Joel Charlebois

AESI Acumen
Engineered
Solutions
International
Inc.

5

NPCC

Mike Cooke

Ontario Power 4
Generation,
Inc.

NPCC

Salvatore
Spagnolo

New York
Power
Authority

1

NPCC

Shivaz Chopra

New York
Power
Authority

5

NPCC

Mike Forte

Con Ed Consolidated
Edison

4

NPCC

Dermot Smyth

Con Ed 1
Consolidated
Edison Co. of
New York

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Ashmeet Kaur

Con Ed Consolidated
Edison

5

NPCC

Caroline Dupuis

Hydro Quebec 1

NPCC

Chantal Mazza

Hydro Quebec 2

NPCC

Sean Bodkin

Dominion Dominion
Resources,
Inc.

6

NPCC

Laura McLeod

NB Power
Corporation

5

NPCC

Randy
MacDonald

NB Power
Corporation

2

NPCC

Gregory Campoli New York
Independent
System
Operator

2

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

John Hastings

National Grid

1

NPCC

Michael Jones

National Grid
USA

1

NPCC

1. The SDT approach is to align the FAC-002-2 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.
Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
I am ok with removing references to retired functions.
However, doing only this separately from normal five year review, "Technical Rationale for Reliability Standards", and “Standards Efficiency” Projects is
time consuming and unnecessary and inefficient.

Likes

0

Dislikes

0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
I am ok with removing references to retired functions.

However, doing only this separately from the normal five year review, "Technical Rationale for Reliability Standards", and “Standards Efficiency”
Projects is time consuming and unnecessary and inefficient.
Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 3
Answer
Document Name

No

Comment
Ameren agrees with EEI and supports the removal of Load Serving Entities from this standard.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

Yes

Document Name
Comment
WECC agrees with the proposed changes but questions whether the Version History Table, last entry, should indicate Version 3 rather than Version 2.
All the other Standards associated with this project identify the newly proposed version as the last entry rather than the current version.
Likes

0

Dislikes

0

Response

Daniel Gacek - Exelon - 1
Answer
Document Name
Comment

Yes

Exelon supports the removal of Load Serving Entities from FAC-002-2.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE noticed the following:
•

In the VSL language, the word “Entity” needs to be removed in the Moderate, High, and Severe language for R3.

•

On Page 8, in the Version History table, it should list version “3” in last box.

Likes

0

Dislikes

0

Response

Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the removal of Load Serving Entities from this standard.
Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer

Yes

Document Name
Comment

Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

LaTroy Brumfield - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Carl Pineault - Hydro-Qu?bec Production - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Stacy Lee - City of College Station - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Trey Melcher - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laurie Hammack - Seattle City Light - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Teresa Cantwell - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Jamie Johnson - California ISO - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

faranak sarbaz - Los Angeles Department of Water and Power - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

2. The SDT approach is to align the IRO-010-2 standard with the RBR initiative by removing references to retired functions. Do you agree with
the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR initiative.
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
NO. See Response to Question 1.
Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer

Yes

Document Name
Comment
Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

Dislikes

0

Response

Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the changes proposed to IRO-10-2.
Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 3
Answer

Yes

Document Name
Comment
Ameren agrees with EEI and supports the changes proposed to IRO-10-2.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE noticed the word “standard” in the header on pages 7 and 8. The word “standard” does not appear in the header on the other pages.
The phrase “Corresponding changes have been made to proposed TOP-003-3.” This should refer to TOP-003-4.
Likes
Dislikes

0
0

Response

Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the changes proposed to IRO-10-2.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

faranak sarbaz - Los Angeles Department of Water and Power - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jamie Johnson - California ISO - 2

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Teresa Cantwell - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laurie Hammack - Seattle City Light - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Trey Melcher - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Stacy Lee - City of College Station - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Carl Pineault - Hydro-Qu?bec Production - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

LaTroy Brumfield - American Transmission Company, LLC - 1
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment

Yes

Likes

0

Dislikes
Response

0

3. The SDT approach is to align the MOD-031-2 and MOD-033-1 standards with the RBR initiative by changing “Planning Authority” to
“Planning Coordinator.” Do you agree with the proposed changes to the standard? If you disagree, please explain and provide alternative
language that will support the RBR initiative.
Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
NO. See Response to Question 1.
Likes

0

Dislikes

0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes
Response

0

Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the changes proposed to MOD-031-2 and MOD-033-1.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE recommends defining “Applicable Entity” since the term is capitalized and used in Requirement R2, Measure M2, Requirement R4, and
Measure M4. The SDT could add the following language in section 4: “For the purpose of the requirements contained herein, the following list of
functional entities will be collectively referred to as Applicable Entities. For requirements in this standard where a specific functional entity or subset of
functional entities are the applicable entity or entities, the functional entity or entities are specified explicitly.” Alternatively, Texas RE recommends
using the term Responsible Entity as that is the term used and defined in the CIP Reliability Standards.

Texas RE noticed the Background section was removed from MOD-033, but not in MOD-031.

Texas RE recommends adding header information regarding the Standard in the Application Guidelines for both MOD-031 and MOD-033 such as was
done in IRO-010 in order to be consistent.
Likes

0

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0

Response

David Jendras - Ameren - Ameren Services - 3
Answer
Document Name

Yes

Comment
Ameren agrees with EEI and supports the changes proposed to MOD-031-2 and MOD-033-1.
Likes

0

Dislikes

0

Response

Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the changes proposed to MOD-031-2 and MOD-033-1.
Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer

Yes

Document Name
Comment
Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

LaTroy Brumfield - American Transmission Company, LLC - 1
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Stacy Lee - City of College Station - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Trey Melcher - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laurie Hammack - Seattle City Light - 3
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Teresa Cantwell - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch

Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jamie Johnson - California ISO - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

faranak sarbaz - Los Angeles Department of Water and Power - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Carl Pineault - Hydro-Qu?bec Production - 5
Answer
Document Name
Comment
N/A
Likes

0

Dislikes
Response

0

4, The SDT approach is to align the NUC-001-3 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
NO. See Response to Question 1.
Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer

Yes

Document Name
Comment
Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

Dislikes

0

Response

Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the changes proposed to NUC-001-4.
Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 3
Answer

Yes

Document Name
Comment
Ameren agrees with EEI and supports the changes proposed to NUC-001-4.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE noticed the Effective Date section is removed, but it exists in the previous standards reviewed (FAC-002-3, IRO-010-3, MOD-031-3, and
MOD-33-2). Texas RE recommends keeping this section to be consistent.
Likes

0

Dislikes
Response

0

Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the changes proposed to NUC-001-3.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

Jamie Johnson - California ISO - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Trey Melcher - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Stacy Lee - City of College Station - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

LaTroy Brumfield - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Teresa Cantwell - Lower Colorado River Authority - 5
Answer
Document Name
Comment
N/A
Likes

0

Dislikes

0

Response

Carl Pineault - Hydro-Qu?bec Production - 5
Answer
Document Name
Comment
N/A
Likes

0

Dislikes
Response

0

5. The SDT approach is to align the PRC-006-3 standard with the RBR initiative and the standard is being revised to add “UFLS OnlyDistribution Provider” consistent with NERC registration criteria. Do you agree with the proposed changes to the standard? If you disagree,
please explain and provide alternative language that will support the RBR initiative.
Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
NO. See Response to Question 1.
Likes

0

Dislikes

0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
Likes

0

Dislikes

0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

No

Document Name
Comment
The language should mimic the ROP such as: " Distribution Provider that operates a required UFLS" and a footnote should be used to refer the reader
to the ROP. Anything less than this tends to cause confusion or result in more questions than it resolves.
Likes
Dislikes

0
0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

No

Document Name
Comment
Reclamation recommends revising the applicability section to eliminate redundancy between 4.2 and 4.3. Since Transmission Owners are identified as
a subset of 4.2, it is not necessary to list them as a separate applicable entity in 4.3. Reclamation recommends the SDT revise 4.2 as follows:
From: 4.2 UFLS entities shall mean all entities that are responsible for the ownership, operation, or control of UFLS equipment as required by the UFLS
program established by the Planning Coordinators. Such entities may include one or more of the following:
4.2.1 Transmission Owners
4.2.2 Distribution Providers

To:
4.2 UFLS entities – all entities that are responsible for the ownership, operation, or control of UFLS equipment or Elements as required by the
UFLS program established by the Planning Coordinator. Such entities may include:
4.2.1 Transmission Owners
4.2.2 Distribution Providers
4.2.3 UFLS-Only Distribution Providers
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes
Response

0

Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the changes proposed to PRC-006-3.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE noticed the following:
•

The attachment still uses PRC-006-3. Should that be updated to PRC-006-4? Thus, Requirements R3 and R4 would need to be updated to
the new attachment name. The Regional Variance for Quebec’s attachment also references PRC-006-3.

•

The Implementation Plan states that “PRC-006 was updated to replace Distribution Providers (DP) with the more-limited UFLS-only DP to the
Applicability Section.” PRC-006-4 appears to add UFLS-Only DPs and not replace DPs. Texas RE suggests revising the implementation plan
to match the standard.

Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 3
Answer

Yes

Document Name
Comment
"Attachment 1" (pg 37) and "Attachment 1A" (pg 39) do not have the titles changed to PRC-006-4. Reference to those two attachments show up on
pages 2, 3, 4, 21, 22, 25, 26 & 27. We believe they would also need to be updated.

Also, on page 1 under Introduction > Applicability, we believe a bullet entitled "4.2.3 UFLS-Only Distribution Providers1" should be added underneath
"4.2.2 Distribution Providers."
Likes

0

Dislikes

0

Response

Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the changes proposed to PRC-006-4.
Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer

Yes

Document Name
Comment
Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer
Document Name
Comment

Yes

Please consider removing the footnote regarding NERC Rules of Procedure, Appendix 5 and link to the NERC website. The footnote appears to be
unnecessary.
Likes

0

Dislikes

0

Response

Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
OPG concurs with the RSC comment.
Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

LaTroy Brumfield - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Stacy Lee - City of College Station - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Trey Melcher - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laurie Hammack - Seattle City Light - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Teresa Cantwell - Lower Colorado River Authority - 5
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Jamie Johnson - California ISO - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

faranak sarbaz - Los Angeles Department of Water and Power - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Carl Pineault - Hydro-Qu?bec Production - 5
Answer
Document Name
Comment
N/A
Likes

0

Dislikes
Response

0

6. The SDT approach is to align the TOP-003-3 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
Likes

0

Dislikes

0

Response

Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
NO. See Response to Question 1.
Likes

0

Dislikes

0

Response

Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer

Yes

Document Name
Comment
Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

Dislikes

0

Response

Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the changes proposed to TOP-003-3.
Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 3
Answer

Yes

Document Name
Comment
Ameren agrees with EEI and supports the changes proposed to TOP-003-3.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE does not have any comments on the revisions to TOP-00-3. Texas RE did notice, however, that the Guidelines and Technical Basis
references the incorrect version of PRC-001.
Likes

0

Dislikes
Response

0

Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the changes proposed to TOP-003-3.
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response

faranak sarbaz - Los Angeles Department of Water and Power - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Jamie Johnson - California ISO - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment

Likes
Dislikes

0
0

Response

Teresa Cantwell - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laurie Hammack - Seattle City Light - 3
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Trey Melcher - Lower Colorado River Authority - 1,5
Answer
Document Name

Yes

Comment

Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Stacy Lee - City of College Station - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Carl Pineault - Hydro-Qu?bec Production - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

LaTroy Brumfield - American Transmission Company, LLC - 1
Answer
Document Name
Comment

Yes

Likes

0

Dislikes

0

Response

Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes
Response

0

Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment

Likes

0

Dislikes

0

Response

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Document Name
Comment

Yes

Likes

0

Dislikes
Response

0

7. Please provide any additional comments for the SDT to consider that you have not already provided for Project 2017-07.
Marty Hostler - Northern California Power Agency - 5,6
Answer
Document Name
Comment
NONE
Likes

0

Dislikes

0

Response

Dennis Sismaet - Northern California Power Agency - 6
Answer
Document Name
Comment
None
Likes

0

Dislikes

0

Response

Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
None
Likes

0

Dislikes
Response

0

Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment
IRO-010-2 is also being reviewed as part of the “Technical Rationale for Reliability Standards” project (proposing to remove the Guidelines and
Technical Basis section, but leaving the version number as IRO-010-2).
Likes

0

Dislikes

0

Response

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
Document Name
Comment
None
Likes

0

Dislikes

0

Response

Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment
None.
Likes

0

Dislikes

0

Response

Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Document Name
Comment
Texas RE noticed Section A 5 Effective Date is removed, but it remains in other standards. In general Texas RE recommends reviewing the standards
to ensure this section is consistent. Texas RE noticed things such as some have 5.1 See Implementation Plan while others just say “See
Implementation Plan” with no 5.1.

Texas RE suggests there is an opportunity to streamline this standard. The Applicability section lists both Generators Owners and more specific
Generator Owners in section 4.1.6.1. It is likely that all Generators Owners will have these agreements so 4.1.6.1 could be removed. Thus,
Requirement R5 could be removed since Requirement R2 applies to all Generator Owners.
Likes

0

Dislikes

0

Response

David Jendras - Ameren - Ameren Services - 3
Answer
Document Name
Comment
None
Likes

0

Dislikes

0

Response

Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer
Document Name
Comment
Please consider using the current NERC format for the revised standards. Please consider revising sections of the standards using current NERC
wording. Example: Compliance section of the standards.
Likes

0

Dislikes
Response

0

Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG concurs with the RSC comment.
Likes

0

Dislikes
Response

0

Consideration of Comments
Project Name:
Comment Period Start Date:

10/29/2019

Comment Period End Date:

12/12/2019

Associated Ballots:

2017-07 Standards Alignment with Registration FAC-002-3 IN 1 ST
2017-07 Standards Alignment with Registration Implementation Plan IN 1 OT
2017-07 Standards Alignment with Registration IRO-010-3 IN 1 ST
2017-07 Standards Alignment with Registration MOD-031-3 IN 1 ST
2017-07 Standards Alignment with Registration MOD-033-2 IN 1 ST
2017-07 Standards Alignment with Registration NUC-001-4 IN 1 ST
2017-07 Standards Alignment with Registration PRC-006-4 IN 1 ST
2017-07 Standards Alignment with Registration TOP-003-4 IN 1 ST

There were 32 sets of responses, including comments from approximately 75 different people from approximately 61 companies representing
10 of the Industry Segments as shown in the table on the following pages.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious consideration
in this process. If you feel there has been an error or omission, you can contact the Vice President of Engineering and Standards, Howard Gugel
(via email) or at (404) 446‐9693.

RELIABILITY | RESILIENCE | SECURITY

Questions
1. The SDT approach is to align the FAC-002-2 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.
2. The SDT approach is to align the IRO-010-2 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.
3. The SDT approach is to align the MOD-031-2 and MOD-033-1 standards with the RBR initiative by changing “Planning Authority” to
“Planning Coordinator.” Do you agree with the proposed changes to the standard? If you disagree, please explain and provide alternative
language that will support the RBR initiative.
4. The SDT approach is to align the NUC-001-3 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.
5. The SDT approach is to align the PRC-006-3 standard with the RBR initiative and the standard is being revised to add “UFLS OnlyDistribution Provider” consistent with NERC registration criteria. Do you agree with the proposed changes to the standard? If you disagree,
please explain and provide alternative language that will support the RBR initiative.
6. The SDT approach is to align the TOP-003-3 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

2

7. Please provide any additional comments for the SDT to consider that you have not already provided for Project 2017-07.

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load‐serving Entities
4 — Transmission‐dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

3

Organization
Name

Name

Segment(s)

Douglas
Webb

Douglas
Webb

Southern
Company Alabama
Power
Company

Joel
3
Dembowski

DTE Energy - Karie
Detroit
Barczak
Edison
Company

Region

Group
Name

MRO,SPP RE WestarKCPL

DTE
Energy DTE
Electric

FRCC,RF,SERC

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

Group
Group
Member
Member
Organization Segment(s)

Group Member
Region

Doug Webb

Westar

1,3,5,6

MRO

Doug Webb

KCP&L

1,3,5,6

MRO

Southern Adrianne
Company Collins

3,4,5

Duke Energy Kim Thomas 1,3,5,6

Group
Member
Name

Southern
1
Company
Services, Inc.

SERC

Bill Shultz

Southern
Company
Generation

5

SERC

Ron Carlsen

Southern
Company
Generation
and Energy
Marketing

6

SERC

Joel
Dembowski

Alabama
Power
Company

3

SERC

Jeffrey
Depriest

DTE Energy - 5
DTE Electric

RF

Daniel
Herring

DTE Energy - 4
DTE Electric

RF

Karie Barczak DTE Energy - 3
DTE Electric

RF

Laura Lee

SERC

Duke Energy 1

4

Duke
Energy
Northeast
Ruida Shu
Power
Coordinating
Council

1,2,3,4,5,6,7,8,9,10 NPCC

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

RSC

Dale
Goodwine

Duke Energy 5

SERC

Greg Cecil

Duke Energy 6

RF

Guy V. Zito

Northeast
10
Power
Coordinating
Council

NPCC

Randy
MacDonald

New
Brunswick
Power

2

NPCC

Glen Smith

Entergy
Services

4

NPCC

Brian
Robinson

Utility
Services

5

NPCC

Alan
Adamson

New York
State
Reliability
Council

7

NPCC

David Burke

Orange &
Rockland
Utilities

3

NPCC

Michele
Tondalo

UI

1

NPCC

Helen Lainis

IESO

2

NPCC

Sean Cavote

PSEG

4

NPCC

Kathleen
Goodman

ISO-NE

2

NPCC

5

David Kiguel

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

Independent NA - Not
Applicable

NPCC

Silvia Mitchell NextEra
Energy Florida
Power and
Light Co.

6

NPCC

Paul
Malozewski

Hydro One
Networks,
Inc.

3

NPCC

Nick
Kowalczyk

Orange and 1
Rockland

NPCC

Joel
Charlebois

AESI 5
Acumen
Engineered
Solutions
International
Inc.

NPCC

Mike Cooke

Ontario
4
Power
Generation,
Inc.

NPCC

Salvatore
Spagnolo

New York
Power
Authority

1

NPCC

Shivaz
Chopra

New York
Power
Authority

5

NPCC

6

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

Mike Forte

Con Ed 4
Consolidated
Edison

NPCC

Dermot
Smyth

Con Ed 1
Consolidated
Edison Co. of
New York

NPCC

Peter Yost

Con Ed 3
Consolidated
Edison Co. of
New York

NPCC

Ashmeet
Kaur

Con Ed 5
Consolidated
Edison

NPCC

Caroline
Dupuis

Hydro
Quebec

1

NPCC

Chantal
Mazza

Hydro
Quebec

2

NPCC

Sean Bodkin

Dominion Dominion
Resources,
Inc.

6

NPCC

Laura
McLeod

NB Power
5
Corporation

NPCC

Randy
MacDonald

NB Power
2
Corporation

NPCC

7

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

Gregory
Campoli

New York
2
Independent
System
Operator

NPCC

Quintin Lee

Eversource
Energy

1

NPCC

John Hastings National Grid 1

NPCC

Michael
Jones

NPCC

National Grid 1
USA

8

1. The SDT approach is to align the FAC-002-2 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.
Summary Responses:
The SDT received comments stating: “… doing only this separately from normal five year review, "Technical Rationale for Reliability
Standards", and “Standards Efficiency” Projects is time consuming and unnecessary and inefficient.” Project 2017-07 was placed on hold for a
substantial period of time to allow the SDT to work closely with other project teams to address standards that needed to be aligned with
Registration in projects that were already open; including Technical Rationale for Reliability Standards, periodic reviews and the Standards
Efficiency Review. This collaboration eliminated many standards that this team would have otherwise taken up. Subsequent to those
collaborations, this project took back up the standards that were not addressed by other projects.
The SDT updated the version number in the Version History Table in agreement with comments received. In addition, the SDT has stricken
“Entity” in the VSL language.
Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
I am ok with removing references to retired functions.
However, doing only this separately from normal five year review, "Technical Rationale for Reliability Standards", and “Standards Efficiency”
Projects is time consuming and unnecessary and inefficient.

Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

9

Response
Thank you for your comment. This project was placed on hold for a substantial period of time to allow the SDT to work closely with other
project teams to address standards that needed to be aligned with Registration in projects that were already open, including Technical
Rationale for Reliability Standards, periodic reviews and the Standards Efficiency Review. This collaboration eliminated many standards that
this team would have otherwise taken up. Subsequent to those collaborations, this project took back up the standards that were not
addressed by other projects.
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
I am ok with removing references to retired functions.

However, doing only this separately from the normal five year review, "Technical Rationale for Reliability Standards", and “Standards
Efficiency” Projects is time consuming and unnecessary and inefficient.
Likes

0

Dislikes

0

Response
Thank you for your comment. This project was placed on hold for a substantial period of time to allow the SDT to work closely with other
project teams to address standards that needed to be aligned with Registration in projects that were already open, including Technical
Rationale for Reliability Standards, periodic reviews and the Standards Efficiency Review. This collaboration eliminated many standards that
this team would have otherwise taken up. Subsequent to those collaborations, this project took back up the standards that were not
addressed by other projects.
David Jendras - Ameren - Ameren Services - 3

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

10

Answer

No

Document Name
Comment
Ameren agrees with EEI and supports the removal of Load Serving Entities from this standard.
Likes

0

Dislikes

0

Response
Thank you for your supportive comment.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Thank you for your support.
Steven Rueckert - Western Electricity Coordinating Council - 10
Answer

Yes

Document Name
Comment
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

11

WECC agrees with the proposed changes but questions whether the Version History Table, last entry, should indicate Version 3 rather than
Version 2. All the other Standards associated with this project identify the newly proposed version as the last entry rather than the current
version.
Likes

0

Dislikes

0

Response
Thank you for your comment. The SDT has updated the version number in the Version History Table.
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the removal of Load Serving Entities from FAC-002-2.
Likes

0

Dislikes

0

Response
Thank you for your support.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

12

Texas RE noticed the following:
•

In the VSL language, the word “Entity” needs to be removed in the Moderate, High, and Severe language for R3.

•

On Page 8, in the Version History table, it should list version “3” in last box.

Likes

0

Dislikes

0

Response
Thank you for your comments. The SDT has updated the VSL language to remove the word “Entity,” as well as changed the version number in
the Version History Table.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the removal of Load Serving Entities from this standard.
Likes

0

Dislikes

0

Response
Thank you for your supportive comment.
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

13

City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer

Yes

Document Name
Comment
Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

Dislikes

0

Response
Thank you for your support.
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

14

Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

15

Thank you for your support.
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

16

Likes

0

Dislikes

0

Response
Thank you for your support.
LaTroy Brumfield - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

17

Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Carl Pineault - Hydro-Qu?bec Production - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

18

Likes

0

Dislikes

0

Response
Thank you for your support.
Stacy Lee - City of College Station - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Trey Melcher - Lower Colorado River Authority - 1,5
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

19

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Laurie Hammack - Seattle City Light - 3
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

20

Dislikes

0

Response
Thank you for your support.
Teresa Cantwell - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch
Answer

Yes

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

21

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Jamie Johnson - California ISO - 2
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

22

Response
Thank you for your support.
faranak sarbaz - Los Angeles Department of Water and Power - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

23

2. The SDT approach is to align the IRO-010-2 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.
Summary Responses:
Texas RE commented that the word “standard” appeared in the redline standard in the header on pages 7 and 8. The SDT has removed the
word “standard” in the redline on Pages 7 and 8. In addition, Texas RE commented that the phrase “Corresponding changes have been made
to proposed TOP-003-3,” and suggested this should be changed to refer to TOP-003-4. The SDT responded that the Guidelines and Technical
Basis Initiative will be revising/updating the Guidelines and Technical Basis through that initiative. However, the corresponding changes
referenced were made to TOP-003-3, not TOP-003-4. The SDT for Project 2017-07 made no change.
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
Likes

0

Dislikes

0

Response
Thank you. Please see response to comment in Question 1.
Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

24

NO. See Response to Question 1.
Likes

0

Dislikes

0

Response
Thank you. Please see response to comment in Question 1.
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer

Yes

Document Name
Comment
Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

Dislikes

0

Response
Thank you for your support.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

25

EEI supports the changes proposed to IRO-10-2.
Likes

0

Dislikes

0

Response
Thank you for your support.
David Jendras - Ameren - Ameren Services - 3
Answer

Yes

Document Name
Comment
Ameren agrees with EEI and supports the changes proposed to IRO-10-2.
Likes

0

Dislikes

0

Response
Thank you for your support.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE noticed the word “standard” in the header on pages 7 and 8. The word “standard” does not appear in the header on the other
pages.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

26

The phrase “Corresponding changes have been made to proposed TOP-003-3.” This should refer to TOP-003-4.
Likes

0

Dislikes

0

Response
Thank you for your comments. In the redline, the word “standard” has been removed in the header on Pages 7 and 8. The Guidelines and
Technical Basis Initiative will be revising/updating the Guidelines and Technical Basis through that process. In addition, the corresponding
changes referenced were made to TOP-003-3, not TOP-003-4 – so no change made.
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the changes proposed to IRO-10-2.
Likes

0

Dislikes

0

Response
Thank you for your support.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

27

Likes

0

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0

Response
Thank you for your support.
faranak sarbaz - Los Angeles Department of Water and Power - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Thank you for your support.
Jamie Johnson - California ISO - 2
Answer

Yes

Document Name
Comment
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0

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0

Response
Thank you for your support.
Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

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Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Thank you for your support.
Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch
Answer

Yes

Document Name
Comment
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0

Dislikes

0

Response
Thank you for your support.
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

29

Dislikes

0

Response
Thank you for your support.
Teresa Cantwell - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Thank you for your support.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Thank you for your support.
Laurie Hammack - Seattle City Light - 3
Answer

Yes

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

30

Document Name
Comment
Likes

0

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0

Response
Thank you for your support.
Trey Melcher - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Thank you for your support.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

31

Response
Thank you for your support.
Stacy Lee - City of College Station - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Thank you for your support.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Thank you for your support.
Carl Pineault - Hydro-Qu?bec Production - 5
Answer

Yes

Document Name
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

32

Comment
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0

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0

Response
Thank you for your support.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Thank you for your support.
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

33

Thank you for your support.
LaTroy Brumfield - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Thank you for your support.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Thank you for your support.
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

34

Likes

0

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0

Response
Thank you for your support.
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Thank you for your support.
Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Thank you for your support.
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

35

Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment
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0

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0

Response
Thank you for your support.
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
Likes

0

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0

Response
Thank you for your support.
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

36

Likes

0

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0

Response
Thank you for your support.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

37

3. The SDT approach is to align the MOD-031-2 and MOD-033-1 standards with the RBR initiative by changing “Planning Authority” to
“Planning Coordinator.” Do you agree with the proposed changes to the standard? If you disagree, please explain and provide alternative
language that will support the RBR initiative.
Summary Response:
Comments were received recommending defining “Applicable Entity” since the term is capitalized and used in Requirement R2, Measure M2,
Requirement R4, and Measure M4. The SDT responded that it would be out of scope for Project 2017-07 to define “Applicable Entity,” but
pointed to “Applicable Entity,” Requirement R1, Part 1.1 of MOD-031 that reads:
1.1. A list of Transmission Planners, Balancing Authorities, and Distribution Providers that are required to provide the data
(“Applicable Entities”).
The SDT struck the Background section in response to comments MOD-031 and updated the headers in the Rationale pages of MOD-031 and
MOD-033 for consistency based on comments received.
Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
NO. See Response to Question 1.
Likes

0

Dislikes

0

Response
Thank you. Please see response to comment in Question 1.
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

38

Document Name
Comment
See Response to Question 1.
Likes

0

Dislikes

0

Response
Thank you. Please see response to comment in Question 1.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Thank you for your support.
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

39

Exelon supports the changes proposed to MOD-031-2 and MOD-033-1.
Likes

0

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0

Response
Thank you for your support.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE recommends defining “Applicable Entity” since the term is capitalized and used in Requirement R2, Measure M2, Requirement R4,
and Measure M4. The SDT could add the following language in section 4: “For the purpose of the requirements contained herein, the
following list of functional entities will be collectively referred to as Applicable Entities. For requirements in this standard where a specific
functional entity or subset of functional entities are the applicable entity or entities, the functional entity or entities are specified
explicitly.” Alternatively, Texas RE recommends using the term Responsible Entity as that is the term used and defined in the CIP Reliability
Standards.

Texas RE noticed the Background section was removed from MOD-033, but not in MOD-031.

Texas RE recommends adding header information regarding the Standard in the Application Guidelines for both MOD-031 and MOD-033
such as was done in IRO-010 in order to be consistent.
Likes

0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

40

Dislikes

0

Response
Thank you for your comments. It is out of scope for Project 2017-07 to define Applicable Entity, but the SDT would like to point you to
“Applicable Entity,” Requirement R1, Part 1.1 of MOD-031 that reads:
1.2. A list of Transmission Planners, Balancing Authorities, and Distribution Providers that are required to provide the data
(“Applicable Entities”).
The Background section has been stricken from MOD-031. This team did update the header in MOD-031 and MOD-033 for consistency.
David Jendras - Ameren - Ameren Services - 3
Answer

Yes

Document Name
Comment
Ameren agrees with EEI and supports the changes proposed to MOD-031-2 and MOD-033-1.
Likes

0

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0

Response
Thank you for your support.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the changes proposed to MOD-031-2 and MOD-033-1.
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

41

Likes

0

Dislikes

0

Response
Thank you for your support.
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek
Brown, Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and
Light Co., 1, 3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains
Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Douglas Webb, Group Name Westar-KCPL
Answer

Yes

Document Name
Comment
Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

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0

Response
Thank you.
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

42

Dislikes

0

Response
Thank you for your support.
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

43

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

44

Response
Thank you for your support.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
LaTroy Brumfield - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

45

Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

46

Thank you for your support.
Stacy Lee - City of College Station - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Trey Melcher - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

47

Likes

0

Dislikes

0

Response
Thank you for your support.
Laurie Hammack - Seattle City Light - 3
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

48

Teresa Cantwell - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch
Answer

Yes

Document Name
Comment

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

49

Likes

0

Dislikes

0

Response
Thank you for your support.
Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Jamie Johnson - California ISO - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
faranak sarbaz - Los Angeles Department of Water and Power - 1
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

50

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Carl Pineault - Hydro-Qu?bec Production - 5
Answer
Document Name
Comment
N/A
Likes

0

Dislikes

0

Response
Thank you for your support.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

51

4. The SDT approach is to align the NUC-001-3 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.
Summary Responses:
Texas RE commented that the Effective Date sections needed to be updated for consistency. The SDT made the corresponding changes for
consistency.
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
Likes

0

Dislikes

0

Response
Thank you. Please see response to comment in Question 1.
Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
NO. See Response to Question 1.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

52

Likes

0

Dislikes

0

Response
Thank you. Please see response to comment in Question 1.
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer

Yes

Document Name
Comment
Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

Dislikes

0

Response
Thank you.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the changes proposed to NUC-001-4.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

53

Likes

0

Dislikes

0

Response
Thank you for your support.
David Jendras - Ameren - Ameren Services - 3
Answer

Yes

Document Name
Comment
Ameren agrees with EEI and supports the changes proposed to NUC-001-4.
Likes

0

Dislikes

0

Response
Thank you for your support.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE noticed the Effective Date section is removed, but it exists in the previous standards reviewed (FAC-002-3, IRO-010-3, MOD-031-3,
and MOD-33-2). Texas RE recommends keeping this section to be consistent.
Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

54

Response
Thank you for your comments. Standards have been updated for a consistent Effective Date Section.
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the changes proposed to NUC-001-3.
Likes

0

Dislikes

0

Response
Thank you for your support.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Thank you for your support.
Jamie Johnson - California ISO - 2
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

55

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

56

Dislikes

0

Response
Thank you for your support.
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Trey Melcher - Lower Colorado River Authority - 1,5
Answer

Yes

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

57

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Stacy Lee - City of College Station - 1
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

58

Response
Thank you for your support.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

59

Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
LaTroy Brumfield - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

60

Thank you for your support.
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

61

Likes

0

Dislikes

0

Response
Thank you for your support.
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

62

Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Teresa Cantwell - Lower Colorado River Authority - 5
Answer
Document Name
Comment
N/A
Likes

0

Dislikes

0

Response
Thank you for your support.
Carl Pineault - Hydro-Qu?bec Production - 5
Answer
Document Name
Comment
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

63

N/A
Likes

0

Dislikes

0

Response
Thank you for your support.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

64

5. The SDT approach is to align the PRC-006-3 standard with the RBR initiative and the standard is being revised to add “UFLS OnlyDistribution Provider” consistent with NERC registration criteria. Do you agree with the proposed changes to the standard? If you disagree,
please explain and provide alternative language that will support the RBR initiative.
Summary Responses:
The SDT received a comment stating that the language should mimic the ROP, as well as a comment to remove the footnote. The SDT
responded that UFLS-only Distribution Provider is a Registered Entity. The SDT did include a footnote in Draft 1 of PRC-006-4 to refer the
reader to the definition of UFLS-only DP in the Rules of Procedure (ROP). The link has been removed from the standard, but the SDT retained
the footnote.
Comments were received that UFLS-only DP should be added underneath "4.2.2 Distribution Providers." The SDT responded that UFLS
entities may or may not include UFLS owners. 4.2 are Entities that are established by the Planning Coordinators; whereas 4.3 are entities
owning UFLS equipment, but are not UFLS entities. In addition, it would be out of scope for Project 2017-7 to draft changes to the
Applicability Section that are not listed in the SAR for alignment with RBR.
The version number has been updated throughout the standard. The Implementation Plan has been updated to: “PRC-006 was updated to
include the more-limited UFLS-only Distribution Provider (DP) to the Applicability Section,” in response to comments received.
Comments were received to define Applicable Entity. It would be out of scope for Project 2017-07 to define Applicable Entity, but the SDT did
point the commenter to “Applicable Entity,” Requirement R1, Part 1.1 of MOD-031 that reads: “A list of Transmission Planners, Balancing
Authorities, and Distribution Providers that are required to provide the data (“Applicable Entities”).”
Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
NO. See Response to Question 1.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

65

Likes

0

Dislikes

0

Response
Thank you. Please see response to comment in Question 1.
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
Likes

0

Dislikes

0

Response
Thank you. Please see response to comment in Question 1.
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

No

Document Name
Comment
The language should mimic the ROP such as: " Distribution Provider that operates a required UFLS" and a footnote should be used to refer the
reader to the ROP. Anything less than this tends to cause confusion or result in more questions than it resolves.
Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

66

Response
Thank you for your comment. UFLS-only Distribution Provider is a Registered Entity. The SDT did include a footnote in Draft 1 of PRC-006-4 to
refer the reader to the definition in the ROP.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

No

Document Name
Comment
Reclamation recommends revising the applicability section to eliminate redundancy between 4.2 and 4.3. Since Transmission Owners are
identified as a subset of 4.2, it is not necessary to list them as a separate applicable entity in 4.3. Reclamation recommends the SDT revise 4.2
as follows:
From: 4.2 UFLS entities shall mean all entities that are responsible for the ownership, operation, or control of UFLS equipment as required by
the UFLS program established by the Planning Coordinators. Such entities may include one or more of the following:
4.2.1 Transmission Owners
4.2.2 Distribution Providers

To: 4.2 UFLS entities – all entities that are responsible for the ownership, operation, or control of UFLS equipment or Elements as required
by the UFLS program established by the Planning Coordinator. Such entities may include:
4.2.1 Transmission Owners
4.2.2 Distribution Providers
4.2.3 UFLS-Only Distribution Providers
Likes

0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

67

Dislikes

0

Response
Thank you for your comment. UFLS entities may or may not include UFLS owners. 4.2 are Entities that are established by the Planning
Coordinators; whereas 4.3 are entities owning UFLS equipment, but are not UFLS entities. In addition, it would be out of scope for Project
2017-7 to draft changes to the Applicability Section that are not listed in the SAR for alignment with RBR.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Thank you for your support.
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the changes proposed to PRC-006-3.
Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

68

Response
Thank you for your support.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE noticed the following:
•

The attachment still uses PRC-006-3. Should that be updated to PRC-006-4? Thus, Requirements R3 and R4 would need to be
updated to the new attachment name. The Regional Variance for Quebec’s attachment also references PRC-006-3.

•

The Implementation Plan states that “PRC-006 was updated to replace Distribution Providers (DP) with the more-limited UFLS-only DP
to the Applicability Section.” PRC-006-4 appears to add UFLS-Only DPs and not replace DPs. Texas RE suggests revising the
implementation plan to match the standard.

Likes

0

Dislikes

0

Response
Thank you for your comments. The version number has been updated throughout the standard. The Implementation Plan has been updated
to: “PRC-006 was updated to include the more limited UFLS-only Distribution Provider (DP) to the Applicability Section.”
David Jendras - Ameren - Ameren Services - 3
Answer

Yes

Document Name
Comment

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

69

"Attachment 1" (pg 37) and "Attachment 1A" (pg 39) do not have the titles changed to PRC-006-4. Reference to those two attachments show
up on pages 2, 3, 4, 21, 22, 25, 26 & 27. We believe they would also need to be updated.
Also, on page 1 under Introduction > Applicability, we believe a bullet entitled "4.2.3 UFLS-Only Distribution Providers1" should be added
underneath "4.2.2 Distribution Providers."
Likes

0

Dislikes

0

Response
Thank you for your comments. The version number has been updated throughout the standard. The Implementation Plan has been updated
to: “PRC-006 was updated to include the more-limited UFLS-only Distribution Provider (DP) to the Applicability Section.” It is out of scope for
Project 2017-07 to define Applicable Entity, but the SDT would like to point you to “Applicable Entity,” Requirement R1, Part 1.1 of MOD-031
that reads:
1.1. A list of Transmission Planners, Balancing Authorities, and Distribution Providers that are required to provide the data
(“Applicable Entities”).
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the changes proposed to PRC-006-4.
Likes

0

Dislikes

0

Response
Thank you for your support.
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

70

Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer

Yes

Document Name
Comment
Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

Dislikes

0

Response
Thank you.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment
Please consider removing the footnote regarding NERC Rules of Procedure, Appendix 5 and link to the NERC website. The footnote appears to
be unnecessary.
Likes

0

Dislikes

0

Response
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

71

Thank you for your comment. The ROP defines UFLS-only DP. The link has been removed from the standard, but the SDT retained a footnote.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
OPG concurs with the RSC comment.
Likes

0

Dislikes

0

Response
Please see responses to RSC comment.
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

72

Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

73

Thank you for your support.
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
LaTroy Brumfield - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Comment
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

74

Likes

0

Dislikes

0

Response
Thank you for your support.
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

75

Stacy Lee - City of College Station - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Trey Melcher - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Laurie Hammack - Seattle City Light - 3
Answer

Yes

Document Name
Comment

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

76

Likes

0

Dislikes

0

Response
Thank you for your support.
Teresa Cantwell - Lower Colorado River Authority - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

77

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Jamie Johnson - California ISO - 2
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

78

Dislikes

0

Response
Thank you for your support.
faranak sarbaz - Los Angeles Department of Water and Power - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Carl Pineault - Hydro-Qu?bec Production - 5
Answer
Document Name
Comment
N/A
Likes

0

Dislikes

0

Response
Thank you for your support.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

79

6. The SDT approach is to align the TOP-003-3 standard with the RBR initiative by removing references to retired functions. Do you agree
with the proposed changes to the standard? If you disagree, please explain and provide alternative language that will support the RBR
initiative.
Summary Responses:
There was a comment received that the Guidelines and Technical Basis references the incorrect version of PRC-001. The SDT responded that
the Guidelines and Technical Basis Initiative could address that comment for the version number of PRC-001, but that this change would be
out of scope for Project 2017-07.
Dennis Sismaet - Northern California Power Agency - 6
Answer

No

Document Name
Comment
See Response to Question 1.
Likes

0

Dislikes

0

Response
Thank you. Please see response to comment in Question 1.
Marty Hostler - Northern California Power Agency - 5,6
Answer

No

Document Name
Comment
NO. See Response to Question 1.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

80

Likes

0

Dislikes

0

Response
Thank you. Please see response to comment in Question 1.
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer

Yes

Document Name
Comment
Westar Energy and Kansas City Power & Light support Edison Electric Institute’s response.
Likes

0

Dislikes

0

Response
Thank you.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer

Yes

Document Name
Comment
EEI supports the changes proposed to TOP-003-3.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

81

Likes

0

Dislikes

0

Response
Thank you for your support.
David Jendras - Ameren - Ameren Services - 3
Answer

Yes

Document Name
Comment
Ameren agrees with EEI and supports the changes proposed to TOP-003-3.
Likes

0

Dislikes

0

Response
Thank you for your support.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer

Yes

Document Name
Comment
Texas RE does not have any comments on the revisions to TOP-00-3. Texas RE did notice, however, that the Guidelines and Technical Basis
references the incorrect version of PRC-001.
Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

82

Response
Thank you for your comment. The Guidelines and Technical Basis Initiative could address your comment for version number PRC-001, but this
change would be out of scope for Project 2017-07.
Daniel Gacek - Exelon - 1
Answer

Yes

Document Name
Comment
Exelon supports the changes proposed to TOP-003-3.
Likes

0

Dislikes

0

Response
Thank you for your support.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer

Yes

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Thank you for your support.
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

83

faranak sarbaz - Los Angeles Department of Water and Power - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Jamie Johnson - California ISO - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Joel Dembowski - Southern Company - Alabama Power Company - 3, Group Name Southern Company
Answer

Yes

Document Name
Comment

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

84

Likes

0

Dislikes

0

Response
Thank you for your support.
Bobbi Welch - Bobbi Welch On Behalf of: David Zwergel, Midcontinent ISO, Inc., 2; - Bobbi Welch
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Teresa Cantwell - Lower Colorado River Authority - 5
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

85

Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Laurie Hammack - Seattle City Light - 3
Answer

Yes

Document Name
Comment
Likes

0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

86

Dislikes

0

Response
Thank you for your support.
Trey Melcher - Lower Colorado River Authority - 1,5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Stacy Lee - City of College Station - 1
Answer

Yes

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

87

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Carl Pineault - Hydro-Qu?bec Production - 5
Answer

Yes

Document Name
Comment
Likes
Dislikes

0
0

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

88

Response
Thank you for your support.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
LaTroy Brumfield - American Transmission Company, LLC - 1
Answer

Yes

Document Name
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

89

Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Thomas Foltz - AEP - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

90

Thank you for your support.
Laura Nelson - IDACORP - Idaho Power Company - 1
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Glen Farmer - Avista - Avista Corporation - 5
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1
Answer

Yes

Document Name
Comment
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

91

Likes

0

Dislikes

0

Response
Thank you for your support.
Leonard Kula - Independent Electricity System Operator - 2
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer

Yes

Document Name
Comment
Likes

0

Dislikes

0

Response
Thank you for your support.
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

92

7. Please provide any additional comments for the SDT to consider that you have not already provided for Project 2017-07.
Summary Response:
There was a comment received stating that IRO-010-2 is also being reviewed as part of the “Technical Rationale for Reliability Standards”
project. Project 2017-07 is proposing version 3 (IRO-010-3) and the SDT has collaborated with the Technical Rationale for Reliability Standards
regarding IRO-010.
The SDT updated the Effective Date Sections for consistency in response to comments received.
Texas RE commented that there was an opportunity to streamline the standard, stating: “The Applicability section lists both Generators
Owners and more specific Generator Owners in section 4.1.6.1. It is likely that all Generators Owners will have these agreements so 4.1.6.1
could be removed. Thus, Requirement R5 could be removed since Requirement R2 applies to all Generator Owners.” The SDT responded that
Generator Owners in Applicability Section would be out of scope for Project 2017-07.
Marty Hostler - Northern California Power Agency - 5,6
Answer
Document Name
Comment
NONE
Likes

0

Dislikes

0

Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

93

Document Name
Comment
None
Likes

0

Dislikes

0

Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
None
Likes

0

Dislikes

0

Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

94

IRO-010-2 is also being reviewed as part of the “Technical Rationale for Reliability Standards” project (proposing to remove the Guidelines
and Technical Basis section, but leaving the version number as IRO-010-2).
Likes

0

Dislikes

0

Response
Project 2017-07 is proposing version 3 (IRO-010-3). The SDT has collaborated with the Technical Rationale for Reliability Standards regarding
IRO-010.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
Document Name
Comment
None
Likes

0

Dislikes

0

Response
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

95

None.
Likes

0

Dislikes

0

Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE noticed Section A 5 Effective Date is removed, but it remains in other standards. In general Texas RE recommends reviewing the
standards to ensure this section is consistent. Texas RE noticed things such as some have 5.1 See Implementation Plan while others just say
“See Implementation Plan” with no 5.1.

Texas RE suggests there is an opportunity to streamline this standard. The Applicability section lists both Generators Owners and more
specific Generator Owners in section 4.1.6.1. It is likely that all Generators Owners will have these agreements so 4.1.6.1 could be
removed. Thus, Requirement R5 could be removed since Requirement R2 applies to all Generator Owners.
Likes

0

Dislikes

0

Response
Thank you for your comments. The SDT updated the Effective Date Sections for consistency. Generator Owners in Applicability Section would
be out of scope for Project 2017-07.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

96

David Jendras - Ameren - Ameren Services - 3
Answer
Document Name
Comment
None
Likes

0

Dislikes

0

Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC
Answer
Document Name
Comment
Please consider using the current NERC format for the revised standards. Please consider revising sections of the standards using current
NERC wording. Example: Compliance section of the standards.
Likes

0

Dislikes

0

Response
Thank you for your comment.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

97

Document Name
Comment
OPG concurs with the RSC comment.
Likes

0

Dislikes

0

Response
Thank you for your comment. Please see response to RSC comment.

Consideration of Comments
Project 2017-07 Standards Alignment with Registration | January 2020

98

Standards Announcement

Project 2017-07 Standards Alignment with Registration
Formal Comment Period Open through December 12, 2019
Ballot Pools Forming through November 27, 2019
Now Available

A 45-day formal comment period for Project 2017-07 Standards Alignment with Registration is open
through 8 p.m. Eastern, Thursday, December 12, 2019 for the following Standards and Implementation
Plan:
•

FAC-002-3 – Facility Interconnection Studies

•

IRO-010-3 – Reliability Coordinator Data Specification and Collection

•

MOD-031-3 – Demand and Energy Data

•

MOD-033-2 – Steady-State and Dynamic System Model Validation

•

NUC-001-4 – Nuclear Plant Interface Coordination

•

PRC-006-4 – Automatic Underfrequency Load Shedding

•

TOP-003-4 – Operational Reliability Data

•

Implementation Plan

Commenting

Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience
issues navigating the SBS, contact Linda Jenkins. An unofficial Word version of the comment form is
posted on the project page.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours
for NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging
into their SBS accounts prior to the last day of a comment/ballot period.

RELIABILITY | RESILIENCE | SECURITY

Next Steps

Initial ballots for the Standards and Implementation Plan, along with non-binding polls for each
associated Violation Risk Factors and Violation Severity Levels, will be conducted December 3-12,
2019.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Laura Anderson (via email) or at
(404) 446-9671.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2017-07 Standards Alignment with Registration
Initial Ballot | October 2019

2

NERC Balloting Tool (/)

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/183)
Ballot Name: 2017-07 Standards Alignment with Registration FAC-002-3 IN 1 ST
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 229
Total Ballot Pool: 258
Quorum: 88.76
Quorum Established Date: 12/12/2019 3:11:16 PM
Weighted Segment Value: 99.69

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

66

1

59

1

0

0

0

4

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

54

1

49

1

0

0

0

1

4

Segment:
4

15

1

11

1

0

0

0

1

3

Segment:
5

62

1

49

0.98

1

0.02

0

2

10

Segment:
6

46

1

36

1

0

0

0

2

8

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

0

1

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
© 2020
9 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Negative
Votes w/o
Comment

Abstain

No
Vote

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

258

6.4

218

6.38

1

0.02

0

10

29

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

None

N/A

1

Berkshire Hathaway
Terry Harbour
Energy - MidAmerican
Energy Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Black Hills Corporation

Wes Wingen

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Affirmative

N/A

1

City Utilities of
Springfield, Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

Douglas Webb

Stephanie Burns

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Affirmative

N/A

Affirmative

N/A

1

PPL Electric Utilities
Brenda Truhe
Corporation
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Scott Miller

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

Affirmative

N/A

1

Unisource - Tucson
John Tolo
Electric
Power
Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

1

Westar Energy

Allen Klassen

1

Western Area Power
Administration

1

Designated
Proxy
Douglas Webb

Ballot

NERC
Memo

Affirmative

N/A

sean erickson

Affirmative

N/A

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of
Springfield, Missouri

Scott Williams

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

Douglas Webb

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

Snohomish County PUD
Holly Chaney
No.
1
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Affirmative

N/A

3

Brandon
McCormick

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City of Poplar Bluff

Neal Williams

None

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

Affirmative

N/A

4 - NERC Ver 4.3.0.0
SeattleMachine
City Light
Hao Li
© 2020
Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

Abstain

N/A

5 - NERC Ver 4.3.0.0
CowlitzMachine
County Name:
PUD ERODVSBSWB01
Deanna Carlson
© 2020

Daniel Valle

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Hydro-Qu?bec Production

Carl Pineault

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
National
Grid USA
Elizabeth Spivak
© 2020
Machine
Name: ERODVSBSWB01

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Don Schmit

Affirmative

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

Affirmative

N/A

6

Con Ed - Consolidated
Christopher
Edison Co. of New York
Overberg
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Previous

1

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Showing 1 to 258 of 258 entries

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Comment Forms

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BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/183)
Ballot Name: 2017-07 Standards Alignment with Registration IRO-010-3 IN 1 ST
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 227
Total Ballot Pool: 255
Quorum: 89.02
Quorum Established Date: 12/12/2019 3:05:39 PM
Weighted Segment Value: 99.36

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

66

1

60

1

0

0

0

3

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

53

1

48

1

0

0

0

1

4

Segment:
4

14

1

11

1

0

0

0

1

2

Segment:
5

61

1

47

0.959

2

0.041

0

2

10

Segment:
6

46

1

36

1

0

0

0

2

8

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

0

1

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
© 2020
9 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Negative
Votes w/o
Comment

Abstain

No
Vote

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

255

6.4

216

6.359

2

0.041

0

9

28

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

None

N/A

1

Berkshire Hathaway
Terry Harbour
Energy - MidAmerican
Energy Co.
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Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Black Hills Corporation

Wes Wingen

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Affirmative

N/A

1

City Utilities of
Springfield, Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

Douglas Webb

Stephanie Burns

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Affirmative

N/A

Affirmative

N/A

1

PPL Electric Utilities
Brenda Truhe
Corporation
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Scott Miller

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Affirmative

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

Affirmative

N/A

1

Unisource - Tucson
John Tolo
Electric
Power
Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

1

Westar Energy

Allen Klassen

1

Western Area Power
Administration

1

Designated
Proxy
Douglas Webb

Ballot

NERC
Memo

Affirmative

N/A

sean erickson

Affirmative

N/A

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of
Springfield, Missouri

Scott Williams

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

Douglas Webb

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

Brandon
McCormick

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Negative

Comments
Submitted

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

Affirmative

N/A

5

Con Ed - Consolidated
William Winters
Edison Co. of New York
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Daniel Valle

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Hydro-Qu?bec Production

Carl Pineault

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

None

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
5
NaturEner USA, LLC
Eric Smith

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Nebraska Public Power
District

Don Schmit

Affirmative

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6
Duke Energy
Greg Cecil
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Affirmative

N/A

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

Portland General Electric
Daniel Mason
Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Affirmative

N/A

6

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Previous

1

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Showing 1 to 255 of 255 entries

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
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NERC Balloting Tool (/)

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/183)
Ballot Name: 2017-07 Standards Alignment with Registration MOD-031-3 IN 1 ST
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 227
Total Ballot Pool: 255
Quorum: 89.02
Quorum Established Date: 12/12/2019 3:11:54 PM
Weighted Segment Value: 99.69

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

66

1

60

1

0

0

0

3

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

53

1

48

1

0

0

0

1

4

Segment:
4

15

1

11

1

0

0

0

1

3

Segment:
5

60

1

49

0.98

1

0.02

0

1

9

Segment:
6

46

1

36

1

0

0

0

2

8

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

0

1

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
© 2020
9 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Negative
Votes w/o
Comment

Abstain

No
Vote

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

255

6.4

218

6.38

1

0.02

0

8

28

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

None

N/A

1

Berkshire Hathaway
Terry Harbour
Energy - MidAmerican
Energy Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Black Hills Corporation

Wes Wingen

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Affirmative

N/A

1

City Utilities of
Springfield, Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

Douglas Webb

Stephanie Burns

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Affirmative

N/A

Affirmative

N/A

1

PPL Electric Utilities
Brenda Truhe
Corporation
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Scott Miller

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Affirmative

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

Affirmative

N/A

1

Unisource - Tucson
John Tolo
Electric
Power
Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

1

Westar Energy

Allen Klassen

1

Western Area Power
Administration

1

Designated
Proxy
Douglas Webb

Ballot

NERC
Memo

Affirmative

N/A

sean erickson

Affirmative

N/A

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of
Springfield, Missouri

Scott Williams

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

Douglas Webb

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

Brandon
McCormick

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City of Poplar Bluff

Neal Williams

None

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

Affirmative

N/A

4 - NERC Ver 4.3.0.0
SeattleMachine
City Light
Hao Li
© 2020
Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
CowlitzMachine
County Name:
PUD ERODVSBSWB01
Deanna Carlson
© 2020

Daniel Valle

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

None

N/A

5 - NERC Ver 4.3.0.0
NaturEner
USA,Name:
LLC ERODVSBSWB01
Eric Smith
© 2020
Machine

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Nebraska Public Power
District

Don Schmit

Affirmative

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

Joe Tarantino

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

None

N/A

6
Entergy
Julie Hall
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Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

Joe Tarantino

Douglas Webb

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Previous

1

Next

Showing 1 to 255 of 255 entries

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NERC Balloting Tool (/)

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/183)
Ballot Name: 2017-07 Standards Alignment with Registration MOD-033-2 IN 1 ST
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 226
Total Ballot Pool: 254
Quorum: 88.98
Quorum Established Date: 12/12/2019 3:12:42 PM
Weighted Segment Value: 99.69

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

66

1

59

1

0

0

0

4

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

53

1

48

1

0

0

0

1

4

Segment:
4

15

1

11

1

0

0

0

1

3

Segment:
5

60

1

49

0.98

1

0.02

0

1

9

Segment:
6

45

1

35

1

0

0

0

2

8

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

0

1

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
© 2020
9 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Negative
Votes w/o
Comment

Abstain

No
Vote

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

254

6.4

216

6.38

1

0.02

0

9

28

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

None

N/A

1

Berkshire Hathaway
Terry Harbour
Energy - MidAmerican
Energy Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Black Hills Corporation

Wes Wingen

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Affirmative

N/A

1

City Utilities of
Springfield, Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

Douglas Webb

Stephanie Burns

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Affirmative

N/A

Affirmative

N/A

1

PPL Electric Utilities
Brenda Truhe
Corporation
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Scott Miller

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

Affirmative

N/A

1

Unisource - Tucson
John Tolo
Electric
Power
Co.
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Joe Tarantino

/

Segment

Organization

Voter

1

Westar Energy

Allen Klassen

1

Western Area Power
Administration

1

Designated
Proxy
Douglas Webb

Ballot

NERC
Memo

Affirmative

N/A

sean erickson

Affirmative

N/A

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of
Springfield, Missouri

Scott Williams

Affirmative

N/A

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

Douglas Webb

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

Brandon
McCormick

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City of Poplar Bluff

Neal Williams

None

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

Affirmative

N/A

4 - NERC Ver 4.3.0.0
SeattleMachine
City Light
Hao Li
© 2020
Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
CowlitzMachine
County Name:
PUD ERODVSBSWB01
Deanna Carlson
© 2020

Daniel Valle

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

None

N/A

5 - NERC Ver 4.3.0.0
NaturEner
USA,Name:
LLC ERODVSBSWB01
Eric Smith
© 2020
Machine

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Nebraska Public Power
District

Don Schmit

Affirmative

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

None

N/A

6
Entergy
Julie Hall
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Previous

1

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Showing 1 to 254 of 254 entries

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
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NERC Balloting Tool (/)

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/183)
Ballot Name: 2017-07 Standards Alignment with Registration NUC-001-4 IN 1 ST
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 206
Total Ballot Pool: 229
Quorum: 89.96
Quorum Established Date: 12/12/2019 3:07:47 PM
Weighted Segment Value: 99.59

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

56

1

44

1

0

0

0

9

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

50

1

41

1

0

0

0

5

4

Segment:
4

12

0.9

9

0.9

0

0

0

2

1

Segment:
5

55

1

38

0.974

1

0.026

0

7

9

Segment:
6

41

1

29

1

0

0

0

7

5

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

0

1

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
© 2020
9 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Negative
Votes w/o
Comment

Abstain

No
Vote

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

229

6.3

175

6.274

1

0.026

0

30

23

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

1

Black Hills Corporation

Wes Wingen

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Affirmative

N/A

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Abstain

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

None

N/A

1

Manitoba Hydro

Bruce Reimer

Abstain

N/A

Affirmative

N/A

1 - NERC Ver 4.3.0.0
MEAGMachine
Power Name: ERODVSBSWB01
David Weekley
© 2020

Douglas Webb

Stephanie Burns

Scott Miller

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Abstain

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Abstain

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Affirmative

N/A

1 - NERC Ver 4.3.0.0
SanteeMachine
Cooper Name: ERODVSBSWB01
Chris Wagner
© 2020

Affirmative

N/A

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Abstain

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Abstain

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Abstain

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

3

Great River Energy

3

Designated
Proxy

Affirmative

N/A

Brian Glover

Affirmative

N/A

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Abstain

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Abstain

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

Affirmative

N/A

3 - NERC Ver 4.3.0.0
Puget Machine
Sound Energy,
Tim Womack
© 2020
Name:Inc.
ERODVSBSWB01

Douglas Webb

Ballot

NERC
Memo

Scott Miller

Brandon
McCormick

/

Segment

Organization

Voter

3

Sacramento Municipal
Utility District

Nicole Looney

3

Santee Cooper

3

Designated
Proxy
Joe Tarantino

Ballot

NERC
Memo

Affirmative

N/A

James Poston

Affirmative

N/A

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Abstain

N/A

3

Tennessee Valley
Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

4

Sacramento Municipal
Utility District

Beth Tincher

4

Seminole Electric
Cooperative, Inc.

4

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Affirmative

N/A

Jonathan Robbins

Abstain

N/A

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Abstain

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Abstain

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

Affirmative

N/A

5

CMS Energy David Greyerbiehl
Consumers Energy
Company
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Joe Tarantino

/

Segment

Organization

Voter

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

5

Cowlitz County PUD

5

Designated
Proxy

Affirmative

N/A

Deanna Carlson

Abstain

N/A

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Abstain

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

Affirmative

N/A

5

Nebraska Public Power
Don Schmit
DistrictMachine Name: ERODVSBSWB01
© 2020 - NERC Ver 4.3.0.0

Daniel Valle

Ballot

NERC
Memo

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Abstain

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Abstain

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

Joe Tarantino

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Abstain

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Manitoba Hydro

Blair Mukanik

Abstain

N/A

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Abstain

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Abstain

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

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/

Segment

Organization

Voter

6

Sacramento Municipal
Utility District

Jamie Cutlip

6

Salt River Project

6

Designated
Proxy
Joe Tarantino

Ballot

NERC
Memo

Affirmative

N/A

Bobby Olsen

Affirmative

N/A

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Abstain

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

Douglas Webb

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Previous

1

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Showing 1 to 229 of 229 entries

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NERC Balloting Tool (/)

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/183)
Ballot Name: 2017-07 Standards Alignment with Registration PRC-006-4 IN 1 ST
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 228
Total Ballot Pool: 256
Quorum: 89.06
Quorum Established Date: 12/12/2019 3:09:53 PM
Weighted Segment Value: 99.38

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

66

1

59

1

0

0

0

4

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

54

1

49

1

0

0

0

1

4

Segment:
4

15

1

11

1

0

0

0

1

3

Segment:
5

60

1

48

0.96

2

0.04

0

1

9

Segment:
6

46

1

36

1

0

0

0

2

8

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

0

1

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
© 2020
9 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Negative
Votes w/o
Comment

Abstain

No
Vote

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

256

6.4

217

6.36

2

0.04

0

9

28

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

None

N/A

1

Berkshire Hathaway
Terry Harbour
Energy - MidAmerican
Energy Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Black Hills Corporation

Wes Wingen

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Affirmative

N/A

1

City Utilities of
Springfield, Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

Douglas Webb

Stephanie Burns

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Affirmative

N/A

Affirmative

N/A

1

PPL Electric Utilities
Brenda Truhe
Corporation
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Scott Miller

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

Affirmative

N/A

1

Unisource - Tucson
John Tolo
Electric
Power
Co.
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Joe Tarantino

/

Segment

Organization

Voter

1

Westar Energy

Allen Klassen

1

Western Area Power
Administration

1

Designated
Proxy
Douglas Webb

Ballot

NERC
Memo

Affirmative

N/A

sean erickson

Affirmative

N/A

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of
Springfield, Missouri

Scott Williams

Affirmative

N/A

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

Douglas Webb

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

Snohomish County PUD
Holly Chaney
No.
1
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Affirmative

N/A

3

Brandon
McCormick

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City of Poplar Bluff

Neal Williams

None

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

Affirmative

N/A

4 - NERC Ver 4.3.0.0
SeattleMachine
City Light
Hao Li
© 2020
Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
CowlitzMachine
County Name:
PUD ERODVSBSWB01
Deanna Carlson
© 2020

Daniel Valle

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

None

N/A

5 - NERC Ver 4.3.0.0
NaturEner
USA,Name:
LLC ERODVSBSWB01
Eric Smith
© 2020
Machine

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Nebraska Public Power
District

Don Schmit

Affirmative

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Negative

Comments
Submitted

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

None

N/A

6
Entergy
Julie Hall
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Previous

1

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Showing 1 to 256 of 256 entries

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
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NERC Balloting Tool (/)

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Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/183)
Ballot Name: 2017-07 Standards Alignment with Registration TOP-003-4 IN 1 ST
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 228
Total Ballot Pool: 257
Quorum: 88.72
Quorum Established Date: 12/12/2019 3:14:18 PM
Weighted Segment Value: 99.69

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

66

1

60

1

0

0

0

3

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

54

1

48

1

0

0

0

1

5

Segment:
4

14

1

11

1

0

0

0

1

2

Segment:
5

62

1

49

0.98

1

0.02

0

2

10

Segment:
6

46

1

36

1

0

0

0

2

8

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

0

1

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
© 2020
9 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Negative
Votes w/o
Comment

Abstain

No
Vote

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

257

6.4

218

6.38

1

0.02

0

9

29

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

None

N/A

1

Berkshire Hathaway
Terry Harbour
Energy - MidAmerican
Energy Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Black Hills Corporation

Wes Wingen

Affirmative

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Affirmative

N/A

1

City Utilities of
Springfield, Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

Douglas Webb

Stephanie Burns

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Affirmative

N/A

Affirmative

N/A

1

PPL Electric Utilities
Brenda Truhe
Corporation
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Scott Miller

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Affirmative

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

Affirmative

N/A

1

Unisource - Tucson
John Tolo
Electric
Power
Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

1

Westar Energy

Allen Klassen

1

Western Area Power
Administration

1

Designated
Proxy
Douglas Webb

Ballot

NERC
Memo

Affirmative

N/A

sean erickson

Affirmative

N/A

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of
Springfield, Missouri

Scott Williams

Affirmative

N/A

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

Douglas Webb

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

None

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

Snohomish County PUD
Holly Chaney
No.
1
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Affirmative

N/A

3

Brandon
McCormick

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

Abstain

N/A

5 - NERC Ver 4.3.0.0
CowlitzMachine
County Name:
PUD ERODVSBSWB01
Deanna Carlson
© 2020

Daniel Valle

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Hydro-Qu?bec Production

Carl Pineault

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
National
Grid USA
Elizabeth Spivak
© 2020
Machine
Name: ERODVSBSWB01

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Don Schmit

Affirmative

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

Affirmative

N/A

6

Con Ed - Consolidated
Christopher
Edison Co. of New York
Overberg
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Previous

1

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Showing 1 to 257 of 257 entries

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NERC Balloting Tool (/)

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Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/183)
Ballot Name: 2017-07 Standards Alignment with Registration Implementation Plan IN 1 OT
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: OT
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 225
Total Ballot Pool: 256
Quorum: 87.89
Quorum Established Date: 12/12/2019 3:17:40 PM
Weighted Segment Value: 99.68

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

66

1

57

1

0

0

0

5

4

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

54

1

48

1

0

0

0

2

4

Segment:
4

14

1

10

1

0

0

0

1

3

Segment:
5

62

1

48

0.98

1

0.02

0

3

10

Segment:
6

45

1

34

1

0

0

0

2

9

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

0

1

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
© 2020
9 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Negative
Votes w/o
Comment

Abstain

No
Vote

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

256

6.4

211

6.38

1

0.02

0

13

31

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Abstain

N/A

None

N/A

1

Berkshire Hathaway
Terry Harbour
Energy - MidAmerican
Energy Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Black Hills Corporation

Wes Wingen

None

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Affirmative

N/A

1

City Utilities of
Springfield, Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

Douglas Webb

Stephanie Burns

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Affirmative

N/A

Affirmative

N/A

1

PPL Electric Utilities
Brenda Truhe
Corporation
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Scott Miller

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

Affirmative

N/A

1

Unisource - Tucson
John Tolo
Electric
Power
Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

1

Westar Energy

Allen Klassen

1

Western Area Power
Administration

1

Designated
Proxy
Douglas Webb

Ballot

NERC
Memo

Affirmative

N/A

sean erickson

Affirmative

N/A

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Abstain

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of
Springfield, Missouri

Scott Williams

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

Douglas Webb

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

Snohomish County PUD
Holly Chaney
No.
1
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Affirmative

N/A

3

Brandon
McCormick

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

None

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Municipal Energy Agency
of Nebraska

Brittany Millard

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Abstain

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
CowlitzMachine
County Name:
PUD ERODVSBSWB01
Deanna Carlson
© 2020

Daniel Valle

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Hydro-Qu?bec Production

Carl Pineault

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Abstain

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
National
Grid USA
Elizabeth Spivak
© 2020
Machine
Name: ERODVSBSWB01

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Don Schmit

Affirmative

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

Affirmative

N/A

6

Con Ed - Consolidated
Christopher
Edison Co. of New York
Overberg
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

None

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

Joe Tarantino

Douglas Webb

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

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1

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration FAC-002-3 Non-binding Poll IN 1 NB
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 214
Total Ballot Pool: 246
Quorum: 86.99
Quorum Established Date: 12/12/2019 3:46:02 PM
Weighted Segment Value: 99.44
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

62

1

44

1

0

0

14

4

Segment:
2

6

0.6

6

0.6

0

0

0

0

Segment:
3

53

1

41

1

0

0

7

5

Segment:
4

13

1

10

1

0

0

1

2

Segment:
5

59

1

40

0.976

1

0.024

8

10

Segment:
6

44

1

28

1

0

0

6

10

Segment:
7

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

1

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

0

0

0

Segment

Segment: 6
0.6
6
0.6
© 2020
10 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Totals:

246

6.4

177

6.376

1

0.024

36

32

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Abstain

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Abstain

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

1

Black Hills Corporation

Wes Wingen

None

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Abstain

N/A

Affirmative

N/A

1

City Utilities of
Michael Buyce
Springfield, Missouri
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Abstain

N/A

1

Long Island Power
Authority

Robert Ganley

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

Douglas Webb

Stephanie Burns

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Abstain

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

None

N/A

Theresa
Rakowsky
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Organization

Voter

1

Sacramento Municipal
Utility District

Arthur Starkovich

1

Salt River Project

1

Designated
Proxy

Affirmative

N/A

Steven Cobb

Affirmative

N/A

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Abstain

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Abstain

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

Affirmative

N/A

2 - NERC Ver 4.3.0.0
ISO New
England,
Inc.ERODVSBSWB01
Michael Puscas
© 2020
Machine
Name:

Joe Tarantino

Ballot

NERC
Memo

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Abstain

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Abstain

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Abstain

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Abstain

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

Douglas Webb

Scott Miller

Brandon
McCormick

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Abstain

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City of Poplar Bluff

Neal Williams

None

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Abstain

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

Affirmative

N/A

5
Avista - Avista
Glen Farmer
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Corporation

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Abstain

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

Daniel Valle

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

5

Great River Energy

5

Designated
Proxy

Affirmative

N/A

Preston Walsh

Affirmative

N/A

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Hydro-Qu?bec Production

Carl Pineault

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Abstain

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Abstain

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Don Schmit

Abstain

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

Affirmative

N/A

5

Omaha Public Power
Mahmood Safi
District
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

Ballot

NERC
Memo

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Abstain

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
WestarMachine
Energy Name: ERODVSBSWB01
Derek Brown
© 2020

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Abstain

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

Affirmative

N/A

6
Manitoba Hydro
Blair Mukanik
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Abstain

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

None

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

Abstain

N/A

6

Seminole Electric
Michael Lee
Cooperative, Inc.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Abstain

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Douglas Webb

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration IRO-010-3 Non-binding Poll IN 1 NB
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 212
Total Ballot Pool: 242
Quorum: 87.6
Quorum Established Date: 12/12/2019 3:32:33 PM
Weighted Segment Value: 99.43
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

62

1

45

1

0

0

13

4

Segment:
2

6

0.6

6

0.6

0

0

0

0

Segment:
3

51

1

39

1

0

0

7

5

Segment:
4

12

1

10

1

0

0

1

1

Segment:
5

58

1

39

0.975

1

0.025

8

10

Segment:
6

44

1

28

1

0

0

7

9

Segment:
7

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

1

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

0

0

0

Segment

Segment: 6
0.6
6
0.6
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10 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

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Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Totals:

242

6.4

175

6.375

1

0.025

36

30

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Abstain

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Abstain

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

1

Black Hills Corporation

Wes Wingen

None

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Abstain

N/A

Affirmative

N/A

1

City Utilities of
Michael Buyce
Springfield, Missouri
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Abstain

N/A

1

Long Island Power
Authority

Robert Ganley

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

Douglas Webb

Stephanie Burns

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Abstain

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

None

N/A

Theresa
Rakowsky
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Organization

Voter

1

Sacramento Municipal
Utility District

Arthur Starkovich

1

Salt River Project

1

Designated
Proxy

Affirmative

N/A

Steven Cobb

Affirmative

N/A

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Affirmative

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Abstain

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Abstain

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

Affirmative

N/A

2 - NERC Ver 4.3.0.0
ISO New
England,
Inc.ERODVSBSWB01
Michael Puscas
© 2020
Machine
Name:

Joe Tarantino

Ballot

NERC
Memo

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Abstain

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Abstain

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Abstain

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Abstain

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

Affirmative

N/A

3

Platte River Power
Wade Kiess
Authority
© 2020 - NERC Ver 4.3.0.0
Machine Name: ERODVSBSWB01

Douglas Webb

Scott Miller

Brandon
McCormick

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Abstain

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Abstain

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Abstain

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5 - NERC Ver 4.3.0.0
Hydro-Qu?bec
Carl Pineault
© 2020
Machine Production
Name: ERODVSBSWB01

Affirmative

N/A

Daniel Valle

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Abstain

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Abstain

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Don Schmit

Abstain

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Abstain

N/A

Affirmative

N/A

5

Public Utility District No. 1
Meaghan Connell
of
Chelan
County
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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Abstain

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

None

N/A

6

Berkshire Hathaway Sandra Shaffer
PacifiCorp
© 2020 - NERC Ver 4.3.0.0
Machine Name: ERODVSBSWB01

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Abstain

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

Abstain

N/A

6

Tennessee Valley
Marjorie Parsons
Authority
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

6

WEC Energy Group, Inc.

David Hathaway

6

Westar Energy

Grant Wilkerson

6

Western Area Power
Administration

8

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Affirmative

N/A

Rosemary Jones

Affirmative

N/A

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Douglas Webb

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration MOD-031-3 Non-binding Poll IN 1 NB
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 211
Total Ballot Pool: 242
Quorum: 87.19
Quorum Established Date: 12/12/2019 3:46:26 PM
Weighted Segment Value: 99.43
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

62

1

45

1

0

0

13

4

Segment:
2

6

0.6

6

0.6

0

0

0

0

Segment:
3

51

1

38

1

0

0

7

6

Segment:
4

13

1

10

1

0

0

1

2

Segment:
5

57

1

40

0.976

1

0.024

7

9

Segment:
6

44

1

28

1

0

0

7

9

Segment:
7

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

1

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

0

0

0

Segment

Segment: 6
0.6
6
0.6
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Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Totals:

242

6.4

175

6.376

1

0.024

35

31

BALLOT POOL MEMBERS
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All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Abstain

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Abstain

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

1

Black Hills Corporation

Wes Wingen

None

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Abstain

N/A

Affirmative

N/A

1

City Utilities of
Michael Buyce
Springfield, Missouri
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Joe Tarantino

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Abstain

N/A

1

Long Island Power
Authority

Robert Ganley

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

Douglas Webb

Stephanie Burns

Scott Miller

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Abstain

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

None

N/A

Theresa
Rakowsky
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Segment

Organization

Voter

1

Sacramento Municipal
Utility District

Arthur Starkovich

1

Salt River Project

1

Designated
Proxy

Affirmative

N/A

Steven Cobb

Affirmative

N/A

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Affirmative

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Abstain

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Abstain

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

Affirmative

N/A

2 - NERC Ver 4.3.0.0
ISO New
England,
Inc.ERODVSBSWB01
Michael Puscas
© 2020
Machine
Name:

Joe Tarantino

Ballot

NERC
Memo

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Abstain

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Abstain

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Abstain

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Abstain

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

Affirmative

N/A

3

Platte River Power
Wade Kiess
Authority
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Douglas Webb

Scott Miller

Brandon
McCormick

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Abstain

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

None

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

None

N/A

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City of Poplar Bluff
Neal Williams

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Abstain

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Abstain

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

Joe Tarantino

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

None

N/A

5 - NERC Ver 4.3.0.0
Lakeland
Electric
Jim Howard
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Machine
Name: ERODVSBSWB01

Daniel Valle

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Lincoln Electric System

Kayleigh
Wilkerson

Abstain

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Abstain

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Don Schmit

Abstain

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Abstain

N/A

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Abstain

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

Joe Tarantino

Douglas Webb

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Abstain

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

Affirmative

N/A

6

Tacoma Public Utilities
Rick Applegate
(Tacoma, WA)
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Tennessee Valley
Authority

Marjorie Parsons

Abstain

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Douglas Webb

Previous

1

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Showing 1 to 242 of 242 entries

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration MOD-033-2 Non-binding Poll IN 1 NB
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 210
Total Ballot Pool: 242
Quorum: 86.78
Quorum Established Date: 12/12/2019 3:51:48 PM
Weighted Segment Value: 99.43
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

62

1

44

1

0

0

14

4

Segment:
2

6

0.6

6

0.6

0

0

0

0

Segment:
3

52

1

39

1

0

0

7

6

Segment:
4

13

1

10

1

0

0

1

2

Segment:
5

57

1

40

0.976

1

0.024

7

9

Segment:
6

43

1

26

1

0

0

7

10

Segment:
7

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

1

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

0

0

0

Segment

Segment: 6
0.6
6
0.6
© 2020
10 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Totals:

242

6.4

173

6.376

1

0.024

36

32

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Abstain

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Abstain

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

1

Black Hills Corporation

Wes Wingen

None

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Abstain

N/A

Affirmative

N/A

1

City Utilities of
Michael Buyce
Springfield, Missouri
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Abstain

N/A

1

Long Island Power
Authority

Robert Ganley

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

Douglas Webb

Stephanie Burns

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Abstain

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

None

N/A

Theresa
Rakowsky
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Organization

Voter

1

Sacramento Municipal
Utility District

Arthur Starkovich

1

Salt River Project

1

Designated
Proxy

Affirmative

N/A

Steven Cobb

Affirmative

N/A

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Abstain

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Abstain

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

Affirmative

N/A

2 - NERC Ver 4.3.0.0
ISO New
England,
Inc.ERODVSBSWB01
Michael Puscas
© 2020
Machine
Name:

Joe Tarantino

Ballot

NERC
Memo

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Abstain

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Abstain

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Abstain

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Abstain

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

Douglas Webb

Scott Miller

Brandon
McCormick

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Abstain

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Affirmative

N/A

None

N/A

3 - NERC Ver 4.3.0.0
Xcel Energy,
Inc.
Joel Limoges
© 2020
Machine
Name: ERODVSBSWB01

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City of Poplar Bluff

Neal Williams

None

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Abstain

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

Abstain

N/A

5

BC Hydro and Power
Helen Hamilton
Authority
Harding
© 2020 - NERC Ver 4.3.0.0
Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

Affirmative

N/A

5

Great Plains Energy Marcus Moor
Kansas City Power and
Light Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Daniel Valle

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Abstain

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Abstain

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Don Schmit

Abstain

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

Affirmative

N/A

5

Platte River Power
Tyson Archie
Authority
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Abstain

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Abstain

N/A

Affirmative

N/A

6

APS - Arizona Public
Chinedu
ServiceMachine
Co.
Ochonogor
© 2020 - NERC Ver 4.3.0.0
Name: ERODVSBSWB01

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

Affirmative

N/A

6

NiSource - Northern
Joe O'Brien
Indiana Public Service
Co. Machine Name: ERODVSBSWB01
© 2020 - NERC Ver 4.3.0.0

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Abstain

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

None

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

Affirmative

N/A

6

Tacoma Public Utilities
Rick Applegate
(Tacoma, WA)
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Tennessee Valley
Authority

Marjorie Parsons

Abstain

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Douglas Webb

Previous

1

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Showing 1 to 242 of 242 entries

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration NUC-001-4 Non-binding Poll IN 1 NB
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 192
Total Ballot Pool: 219
Quorum: 87.67
Quorum Established Date: 12/12/2019 3:47:00 PM
Weighted Segment Value: 99.31
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

53

1

34

1

0

0

15

4

Segment:
2

6

0.6

6

0.6

0

0

0

0

Segment:
3

49

1

34

1

0

0

9

6

Segment:
4

11

0.8

8

0.8

0

0

2

1

Segment:
5

52

1

31

0.969

1

0.031

12

8

Segment:
6

39

1

22

1

0

0

10

7

Segment:
7

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

1

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

0

0

0

Segment

Segment: 6
0.6
6
0.6
© 2020
10 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Totals:

219

6.2

143

6.169

1

0.031

48

27

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Abstain

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

1

Black Hills Corporation

Wes Wingen

None

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Abstain

N/A

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

Affirmative

N/A

1
Colorado Springs Utilities
Mike Braunstein
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Abstain

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Abstain

N/A

1

Long Island Power
Authority

Robert Ganley

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

None

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

Douglas Webb

Stephanie Burns

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Abstain

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Abstain

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Steven Cobb

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Abstain

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Abstain

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Abstain

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Abstain

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

BC Hydro and Power
Authority

Hootan Jarollahi

Abstain

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Abstain

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Abstain

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
3
National Grid USA
Brian Shanahan

Douglas Webb

Scott Miller

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Abstain

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

Affirmative

N/A

3

Southern Company Joel Dembowski
Alabama Power
Company
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Brandon
McCormick

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Abstain

N/A

3

Tennessee Valley
Authority

Ian Grant

Abstain

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

None

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Abstain

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

Abstain

N/A

5

Ameren - Ameren
Sam Dwyer
Missouri
© 2020 - NERC Ver 4.3.0.0
Machine Name: ERODVSBSWB01

Douglas Webb

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Abstain

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Abstain

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
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Cynthia Lee
© 2020

Daniel Valle

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Abstain

N/A

5

Manitoba Hydro

Yuguang Xiao

Abstain

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Abstain

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

Nebraska Public Power
District

Don Schmit

Abstain

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Abstain

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

Affirmative

N/A

5

Ontario Power
Constantin
Generation Inc.
Chitescu
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Abstain

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Abstain

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Abstain

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
6
Black Hills Corporation
Eric Scherr

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Manitoba Hydro

Blair Mukanik

Abstain

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Abstain

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Portland General Electric
Co.

Daniel Mason

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Abstain

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

None

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Abstain

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Abstain

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

None

N/A

Roger
Zaklukiewicz
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Previous

1

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Showing 1 to 219 of 219 entries

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Comment Forms

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration PRC-006-4 Non-binding Poll IN 1 NB
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 209
Total Ballot Pool: 242
Quorum: 86.36
Quorum Established Date: 12/12/2019 3:52:42 PM
Weighted Segment Value: 98.84
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

62

1

44

1

0

0

14

4

Segment:
2

6

0.6

6

0.6

0

0

0

0

Segment:
3

51

1

37

1

0

0

7

7

Segment:
4

13

1

10

1

0

0

1

2

Segment:
5

57

1

39

0.951

2

0.049

7

9

Segment:
6

44

1

27

1

0

0

7

10

Segment:
7

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

1

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

0

0

0

Segment

Segment: 6
0.6
6
0.6
© 2020
10 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Totals:

242

6.4

171

6.351

2

0.049

36

33

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Abstain

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Abstain

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

1

Black Hills Corporation

Wes Wingen

None

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Abstain

N/A

Affirmative

N/A

1

City Utilities of
Michael Buyce
Springfield, Missouri
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Abstain

N/A

1

Long Island Power
Authority

Robert Ganley

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

Douglas Webb

Stephanie Burns

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Abstain

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

None

N/A

Theresa
Rakowsky
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Organization

Voter

1

Sacramento Municipal
Utility District

Arthur Starkovich

1

Salt River Project

1

Designated
Proxy

Affirmative

N/A

Steven Cobb

Affirmative

N/A

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Abstain

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Abstain

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

Affirmative

N/A

2 - NERC Ver 4.3.0.0
ISO New
England,
Inc.ERODVSBSWB01
Michael Puscas
© 2020
Machine
Name:

Joe Tarantino

Ballot

NERC
Memo

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Abstain

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Abstain

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Abstain

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Abstain

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

Affirmative

N/A

3

Platte River Power
Wade Kiess
Authority
© 2020 - NERC Ver 4.3.0.0
Machine Name: ERODVSBSWB01

Douglas Webb

Scott Miller

Brandon
McCormick

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

None

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Abstain

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

None

N/A

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

None

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
4
City of Poplar Bluff
Neal Williams

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Abstain

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Abstain

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

None

N/A

5 - NERC Ver 4.3.0.0
Lakeland
Electric
Jim Howard
© 2020
Machine
Name: ERODVSBSWB01

Daniel Valle

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Lincoln Electric System

Kayleigh
Wilkerson

Abstain

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Abstain

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Don Schmit

Abstain

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Abstain

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Negative

Comments
Submitted

5

Westar Energy

Derek Brown

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Abstain

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Abstain

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

None

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

Affirmative

N/A

6

Tacoma Public Utilities
Rick Applegate
(Tacoma, WA)
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Tennessee Valley
Authority

Marjorie Parsons

Abstain

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Douglas Webb

Previous

1

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Showing 1 to 242 of 242 entries

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration TOP-003-4 Non-binding Poll IN 1 NB
Voting Start Date: 12/3/2019 12:01:00 AM
Voting End Date: 12/12/2019 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 211
Total Ballot Pool: 244
Quorum: 86.48
Quorum Established Date: 12/12/2019 3:53:05 PM
Weighted Segment Value: 99.43
Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Segment:
1

62

1

45

1

0

0

13

4

Segment:
2

6

0.6

6

0.6

0

0

0

0

Segment:
3

52

1

38

1

0

0

7

7

Segment:
4

12

1

10

1

0

0

1

1

Segment:
5

59

1

40

0.976

1

0.024

8

10

Segment:
6

44

1

27

1

0

0

7

10

Segment:
7

0

0

0

0

0

0

0

0

Segment:
8

2

0.1

1

0.1

0

0

0

1

Segment:
9

1

0.1

1

0.1

0

0

0

0

0

0

0

0

Segment

Segment: 6
0.6
6
0.6
© 2020
10 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes

Negative
Fraction

Abstain

No
Vote

Totals:

244

6.4

174

6.376

1

0.024

36

33

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren
Services

Eric Scott

Abstain

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

John Shaver

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Abstain

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

1

Black Hills Corporation

Wes Wingen

None

N/A

1

CenterPoint Energy
Houston Electric, LLC

Daniela
Hammons

Abstain

N/A

Affirmative

N/A

1

City Utilities of
Michael Buyce
Springfield, Missouri
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CMS Energy Consumers Energy
Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International
Transmission Company
Holdings Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Abstain

N/A

1

Long Island Power
Authority

Robert Ganley

Abstain

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

Douglas Webb

Stephanie Burns

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Abstain

N/A

1

New York Power
Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service
Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Nathaniel Clague

Abstain

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

Public Utility District No. 1
of Chelan County

Jeff Kimbell

Affirmative

N/A

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

None

N/A

Theresa
Rakowsky
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Organization

Voter

1

Sacramento Municipal
Utility District

Arthur Starkovich

1

Salt River Project

1

Designated
Proxy

Affirmative

N/A

Steven Cobb

Affirmative

N/A

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Affirmative

N/A

1

Tennessee Valley
Authority

Gabe Kurtz

Abstain

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Abstain

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

Affirmative

N/A

2 - NERC Ver 4.3.0.0
ISO New
England,
Inc.ERODVSBSWB01
Michael Puscas
© 2020
Machine
Name:

Joe Tarantino

Ballot

NERC
Memo

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

2

Midcontinent ISO, Inc.

David Zwergel

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren
Services

David Jendras

Abstain

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Abstain

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

CMS Energy Consumers Energy
Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Abstain

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Edison International Southern California
Edison Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Abstain

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Abstain

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Dmitriy Bazylyuk

Affirmative

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

Douglas Webb

Scott Miller

Brandon
McCormick

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

None

N/A

3

Seminole Electric
Cooperative, Inc.

Kristine Ward

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power
Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley
Authority

Ian Grant

Abstain

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Affirmative

N/A

None

N/A

3 - NERC Ver 4.3.0.0
Xcel Energy,
Inc.
Joel Limoges
© 2020
Machine
Name: ERODVSBSWB01

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

4

Alliant Energy
Corporation Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City Utilities of
Springfield, Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren
Missouri

Sam Dwyer

Abstain

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista
Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Abstain

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
Black Hills
Corporation
George Tatar
© 2020
Machine
Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California
Edison Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

Affirmative

N/A

5
Great River Energy
Preston Walsh
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Daniel Valle

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Herb Schrayshuen

Herb
Schrayshuen

Affirmative

N/A

5

Hydro-Qu?bec Production

Carl Pineault

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Abstain

N/A

5

Los Angeles Department
of Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Abstain

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Don Schmit

Abstain

N/A

5

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

Comments
Submitted

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power
Generation Inc.

Constantin
Chitescu

Affirmative

N/A

Affirmative

N/A

5

Platte River Power
Tyson Archie
Authority
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Abstain

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

Abstain

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

None

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Los Angeles Department
of Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

None

N/A

6
NextEra Energy - Florida
Justin Welty
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Power and Light Co.

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

None

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Luiggi Beretta

Abstain

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

None

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

Affirmative

N/A

6

Southern Company Ron Carlsen
Southern Company
© 2020 - NERC Ver 4.3.0.0
Machine Name: ERODVSBSWB01
Generation

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Abstain

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

None

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

Douglas Webb

Previous

1

Next

Showing 1 to 244 of 244 entries

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

FAC-002-3 — Facility Interconnection Studies

A. Introduction
1.

Title:

Facility Interconnection Studies

2.

Number:

FAC-002-3

3.

Purpose: To study the impact of interconnecting new or materially modified
Facilities on the Bulk Electric System.

4.

Applicability:
4.1. Functional Entities:
4.1.1 Planning Coordinator
4.1.2 Transmission Planner
4.1.3 Transmission Owner
4.1.4 Distribution Provider
4.1.5 Generator Owner
4.1.6 Applicable Generator Owner

5.

4.1.6.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
Effective Date: See Implementation Plan

B. Requirements and Measures
R1.

Each Transmission Planner and each Planning Coordinator shall study the reliability
impact of: (i) interconnecting new generation, transmission, or electricity end-user
Facilities and (ii) materially modifying existing interconnections of generation,
transmission, or electricity end-user Facilities. The following shall be studied:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
1.1. The reliability impact of the new interconnection, or materially modified existing
interconnection, on affected system(s);
1.2. Adherence to applicable NERC Reliability Standards; regional and Transmission
Owner planning criteria; and Facility interconnection requirements;
1.3. Steady-state, short-circuit, and dynamics studies, as necessary, to evaluate
system performance under both normal and contingency conditions; and
1.4. Study assumptions, system performance, alternatives considered, and
coordinated recommendations. While these studies may be performed
independently, the results shall be evaluated and coordinated by the entities
involved.

Draft 2 of FAC-002-3
January 2020

Page 1 of 9

FAC-002-3 — Facility Interconnection Studies

M1. Each Transmission Planner or each Planning Coordinator shall have evidence (such as
study reports, including documentation of reliability issues) that it met all
requirements in Requirement R1.
R2.

Each Generator Owner seeking to interconnect new generation Facilities, or to
materially modify existing interconnections of generation Facilities, shall coordinate
and cooperate on studies with its Transmission Planner or Planning Coordinator,
including but not limited to the provision of data as described in R1, Parts 1.1-1.4.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M2. Each Generator Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R2.
R3.

Each Transmission Owner and each Distribution Provider seeking to interconnect new
transmission Facilities or electricity end-user Facilities, or to materially modify existing
interconnections of transmission Facilities or electricity end-user Facilities, shall
coordinate and cooperate on studies with its Transmission Planner or Planning
Coordinator, including but not limited to the provision of data as described in R1,
Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M3. Each Transmission Owner and each Distribution Provider shall have evidence (such as
documents containing the data provided in response to the requests of the
Transmission Planner or Planning Coordinator) that it met all requirements in
Requirement R3.
R4.

Each Transmission Owner shall coordinate and cooperate with its Transmission
Planner or Planning Coordinator on studies regarding requested new or materially
modified interconnections to its Facilities, including but not limited to the provision of
data as described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

M4. Each Transmission Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R4.
R5.

Each applicable Generator Owner shall coordinate and cooperate with its
Transmission Planner or Planning Coordinator on studies regarding requested
interconnections to its Facilities, including but not limited to the provision of data as
described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon: Longterm Planning]

M5. Each applicable Generator Owner shall have evidence (such as documents containing
the data provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R5.

Draft 2 of FAC-002-3
January 2020

Page 2 of 9

FAC-002-3 — Facility Interconnection Studies

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the CEA may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Planning Coordinator, Transmission Planner, Transmission Owner,
Distribution Provider, Generator Owner and applicable Generator Owner shall
keep data or evidence to show compliance as identified below unless directed by
its CEA to retain specific evidence for a longer period of time as part of an
investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Draft 2 of FAC-002-3
January 2020

Page 3 of 9

FAC-002-3 — Facility Interconnection Studies

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

R1

Long-term
Planning

Medium The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities, but failed to
study one of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study two of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study three of the
Parts (R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator failed to
study the reliability
impact of:
interconnecting new
generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of,
generation,
transmission, or
electricity end-user
Facilities.

R2

Long-term
Planning

Medium The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

Draft 2 of FAC-002-3
January 2020

Page 4 of 9

FAC-002-3 — Facility Interconnection Studies

R#

R3

Time
Horizon

Long-term
Planning

Draft 2 of FAC-002-3
January 2020

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but
failed to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but
failed to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

failed to coordinate
and cooperate on
studies with its
Transmission Planner
or Planning
Coordinator.

Medium The Transmission
Owner or Distribution
Provider seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but

The Transmission
Owner, or Distribution
Provider seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but

The Transmission
Owner or Distribution
Provider seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but failed

The Transmission
Owner, or Distribution
Provider seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, failed to
coordinate and
cooperate on studies
with its Transmission

Page 5 of 9

FAC-002-3 — Facility Interconnection Studies

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

failed to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

failed to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

Planner or Planning
Coordinator.

R4

Long-term
Planning

Medium The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

The Transmission
Owner failed to
coordinate and
cooperate on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities.

R5

Long-term
Planning

Medium The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning

The applicable
Generator Owner
failed to coordinate
and cooperate on
studies with its
Transmission Planner

Draft 2 of FAC-002-3
January 2020

Page 6 of 9

FAC-002-3 — Facility Interconnection Studies

R#

Time
Horizon

Draft 2 of FAC-002-3
January 2020

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

or Planning
Coordinator regarding
requested
interconnections to its
Facilities.

Page 7 of 9

FAC-002-3 — Facility Interconnection Studies

D. Regional Variances
None.

E. Interpretations
None.

F. Associated Documents
None

Draft 2 of FAC-002-3
January 2020

Page 8 of 9

Application Guidelines

Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether
an existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.

Version History
Version

Date

Action

Change
Tracking

0

April 1, 2005

Effective Date

New

0

January 13, 2006

Removed duplication of “Regional
Reliability Organizations(s).

Errata

1

August 5, 2010

Modified to address Order No. 693
Directives contained in paragraph
693.
Adopted by the NERC Board of
Trustees.

Revised

1

February 7, 2013

R2 and associated elements
approved by NERC Board of Trustees
for retirement as part of the
Paragraph 81 project (Project 201302) pending applicable regulatory
approval.

1

November 21, 2013 R2 and associated elements
approved by FERC for retirement as
part of the Paragraph 81 project
(Project 2013-02)

2

Revisions to implement the
recommendations of the FAC FiveYear Review Team.

2

August 14, 2014

Adopted by the Board of Trustees.

2

November 6, 2014

FERC letter order issued approving
FAC-002-2.

3

Draft 2 of FAC-002-3
January 2020

Revision under
Project 2010-02

Adopted by the Board of Trustees.

Page 9 of 9

FAC-002-3 — Facility Interconnection Studies

A. Introduction
1.

Title:

Facility Interconnection Studies

2.

Number:

FAC-002-3

3.

Purpose: To study the impact of interconnecting new or materially modified
Facilities on the Bulk Electric System.

4.

Applicability:
4.1. Functional Entities:
4.1.1 Planning Coordinator
4.1.2 Transmission Planner
4.1.3 Transmission Owner
4.1.4 Distribution Provider
4.1.5 Generator Owner
4.1.6 Applicable Generator Owner

5.

4.1.6.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
Effective Date: See Implementation Plan

B. Requirements and Measures
R1.

Each Transmission Planner and each Planning Coordinator shall study the reliability
impact of: (i) interconnecting new generation, transmission, or electricity end-user
Facilities and (ii) materially modifying existing interconnections of generation,
transmission, or electricity end-user Facilities. The following shall be studied:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
1.1. The reliability impact of the new interconnection, or materially modified existing
interconnection, on affected system(s);
1.2. Adherence to applicable NERC Reliability Standards; regional and Transmission
Owner planning criteria; and Facility interconnection requirements;
1.3. Steady-state, short-circuit, and dynamics studies, as necessary, to evaluate
system performance under both normal and contingency conditions; and
1.4. Study assumptions, system performance, alternatives considered, and
coordinated recommendations. While these studies may be performed
independently, the results shall be evaluated and coordinated by the entities
involved.

Draft 1 2 of FAC-002-3
October January 201920

Page 1 of 9

FAC-002-3 — Facility Interconnection Studies

M1. Each Transmission Planner or each Planning Coordinator shall have evidence (such as
study reports, including documentation of reliability issues) that it met all
requirements in Requirement R1.
R2.

Each Generator Owner seeking to interconnect new generation Facilities, or to
materially modify existing interconnections of generation Facilities, shall coordinate
and cooperate on studies with its Transmission Planner or Planning Coordinator,
including but not limited to the provision of data as described in R1, Parts 1.1-1.4.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M2. Each Generator Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R2.
R3.

Each Transmission Owner and each Distribution Provider seeking to interconnect new
transmission Facilities or electricity end-user Facilities, or to materially modify existing
interconnections of transmission Facilities or electricity end-user Facilities, shall
coordinate and cooperate on studies with its Transmission Planner or Planning
Coordinator, including but not limited to the provision of data as described in R1,
Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M3. Each Transmission Owner and each Distribution Provider shall have evidence (such as
documents containing the data provided in response to the requests of the
Transmission Planner or Planning Coordinator) that it met all requirements in
Requirement R3.
R4.

Each Transmission Owner shall coordinate and cooperate with its Transmission
Planner or Planning Coordinator on studies regarding requested new or materially
modified interconnections to its Facilities, including but not limited to the provision of
data as described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

M4. Each Transmission Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R4.
R5.

Each applicable Generator Owner shall coordinate and cooperate with its
Transmission Planner or Planning Coordinator on studies regarding requested
interconnections to its Facilities, including but not limited to the provision of data as
described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon: Longterm Planning]

M5. Each applicable Generator Owner shall have evidence (such as documents containing
the data provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R5.

Draft 1 2 of FAC-002-3
October January 201920

Page 2 of 9

FAC-002-3 — Facility Interconnection Studies

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the CEA may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Planning Coordinator, Transmission Planner, Transmission Owner,
Distribution Provider, Generator Owner and applicable Generator Owner shall
keep data or evidence to show compliance as identified below unless directed by
its CEA to retain specific evidence for a longer period of time as part of an
investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Draft 1 2 of FAC-002-3
October January 201920

Page 3 of 9

FAC-002-3 — Facility Interconnection Studies

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

R1

Long-term
Planning

Medium The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities, but failed to
study one of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study two of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study three of the
Parts (R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator failed to
study the reliability
impact of:
interconnecting new
generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of,
generation,
transmission, or
electricity end-user
Facilities.

R2

Long-term
Planning

Medium The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,

Draft 1 2 of FAC-002-3
October January 20192020

Page 4 of 9

FAC-002-3 — Facility Interconnection Studies

R#

R3

Time
Horizon

Long-term
Planning

Draft 1 2 of FAC-002-3
October January 20192020

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but
failed to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but
failed to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

failed to coordinate
and cooperate on
studies with its
Transmission Planner
or Planning
Coordinator.

Medium The Transmission
Owner or Distribution
Provider seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but

The Transmission
Owner, or Distribution
Provider Entity
seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning

The Transmission
Owner or Distribution
Provider Entity
seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning

The Transmission
Owner, or Distribution
Provider Entity
seeking to
interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, failed to
coordinate and
cooperate on studies
with its Transmission

Page 5 of 9

FAC-002-3 — Facility Interconnection Studies

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

failed to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

Coordinator, but
failed to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

Coordinator, but failed Planner or Planning
to provide data
Coordinator.
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

R4

Long-term
Planning

Medium The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

The Transmission
Owner failed to
coordinate and
cooperate on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities.

R5

Long-term
Planning

Medium The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission

The applicable
Generator Owner
failed to coordinate
and cooperate on
studies with its

Draft 1 2 of FAC-002-3
October January 20192020

Page 6 of 9

FAC-002-3 — Facility Interconnection Studies

R#

Time
Horizon

Draft 1 2 of FAC-002-3
October January 20192020

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

Transmission Planner
or Planning
Coordinator regarding
requested
interconnections to its
Facilities.

Page 7 of 9

FAC-002-3 — Facility Interconnection Studies

D. Regional Variances
None.

E. Interpretations
None.

F. Associated Documents
None

Draft 1 2 of FAC-002-3
October January
20192020

Page 8 of 9

Application Guidelines

Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether
an existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.

Version History
Version

Date

Action

Change
Tracking

0

April 1, 2005

Effective Date

New

0

January 13, 2006

Removed duplication of “Regional
Reliability Organizations(s).

Errata

1

August 5, 2010

Modified to address Order No. 693
Directives contained in paragraph
693.
Adopted by the NERC Board of
Trustees.

Revised

1

February 7, 2013

R2 and associated elements
approved by NERC Board of Trustees
for retirement as part of the
Paragraph 81 project (Project 201302) pending applicable regulatory
approval.

1

November 21, 2013 R2 and associated elements
approved by FERC for retirement as
part of the Paragraph 81 project
(Project 2013-02)

2

Revisions to implement the
recommendations of the FAC FiveYear Review Team.

2

August 14, 2014

Adopted by the Board of Trustees.

2

November 6, 2014

FERC letter order issued approving
FAC-002-2.

23

Draft 1 2 of FAC-002-3
October January 20192020

Revision under
Project 2010-02

Adopted by the Board of Trustees.

Page 9 of 9

FAC-002-2 3 — Facility Interconnection Studies

A. Introduction
1.

Title:

Facility Interconnection Studies

2.

Number:

FAC-002-32

3.

Purpose: To study the impact of interconnecting new or materially modified
Facilities on the Bulk Electric System.

4.

Applicability:
4.1. Functional Entities:
4.1.1

Planning Coordinator

4.1.2

Transmission Planner

4.1.3

Transmission Owner

4.1.4

Distribution Provider

4.1.5

Generator Owner

4.1.6

Applicable Generator Owner

4.1.6.1 Generator Owner with a fully executed Agreement to conduct a study
on the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility that is used to interconnect to the
Transmission system.
4.1.7 Load-Serving Entity
5.

Effective Date: See Implementation Plan. The first day of the first calendar quarter
that is one year after the date that this 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 that is one year after
the date this standard is adopted by the NERC Board of Trustees or as otherwise
provided for in that jurisdiction.

B. Requirements and Measures
R1. Each Transmission Planner and each Planning Coordinator shall study the reliability
impact of: (i) interconnecting new generation, transmission, or electricity end-user
Facilities and (ii) materially modifying existing interconnections of generation,
transmission, or electricity end-user Facilities. The following shall be studied:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
1.1. The reliability impact of the new interconnection, or materially modified existing
interconnection, on affected system(s);
1.2. Adherence to applicable NERC Reliability Standards; regional and Transmission
Owner planning criteria; and Facility interconnection requirements;
1.3. Steady-state, short-circuit, and dynamics studies, as necessary, to evaluate system
performance under both normal and contingency conditions; and

Page 1 of 8

FAC-002-2 3 — Facility Interconnection Studies

1.4. Study assumptions, system performance, alternatives considered, and coordinated
recommendations. While these studies may be performed independently, the
results shall be evaluated and coordinated by the entities involved.
M1. Each Transmission Planner or each Planning Coordinator shall have evidence (such as
study reports, including documentation of reliability issues) that it met all requirements
in Requirement R1.
R2. Each Generator Owner seeking to interconnect new generation Facilities, or to
materially modify existing interconnections of generation Facilities, shall coordinate
and cooperate on studies with its Transmission Planner or Planning Coordinator,
including but not limited to the provision of data as described in R1, Parts 1.1-1.4.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M2. Each Generator Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R2.
R3. Each Transmission Owner, and each Distribution Provider, and each Load-Serving
Entity seeking to interconnect new transmission Facilities or electricity end-user
Facilities, or to materially modify existing interconnections of transmission Facilities
or electricity end-user Facilities, shall coordinate and cooperate on studies with its
Transmission Planner or Planning Coordinator, including but not limited to the
provision of data as described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
M3. Each Transmission Owner, and each Distribution Provider, and each Load-Serving
Entity shall have evidence (such as documents containing the data provided in response
to the requests of the Transmission Planner or Planning Coordinator) that it met all
requirements in Requirement R3.
R4. Each Transmission Owner shall coordinate and cooperate with its Transmission
Planner or Planning Coordinator on studies regarding requested new or materially
modified interconnections to its Facilities, including but not limited to the provision of
data as described in R1, Parts 1.1-1.4. [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
M4. Each Transmission Owner shall have evidence (such as documents containing the data
provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R4.
R5. Each applicable Generator Owner shall coordinate and cooperate with its Transmission
Planner or Planning Coordinator on studies regarding requested interconnections to its
Facilities, including but not limited to the provision of data as described in R1, Parts
1.1-1.4. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
M5. Each applicable Generator Owner shall have evidence (such as documents containing
the data provided in response to the requests of the Transmission Planner or Planning
Coordinator) that it met all requirements in Requirement R5.

Page 2 of 8

FAC-002-2 3 — Facility Interconnection Studies

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” (CEA) means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the CEA may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.
The Planning Coordinator, Transmission Planner, Transmission Owner,
Distribution Provider, Generator Owner, and applicable Generator Owner, and
Load-Serving Entity shall keep data or evidence to show compliance as identified
below unless directed by its CEA to retain specific evidence for a longer period of
time as part of an investigation:
The responsible entities shall retain documentation as evidence for three years.
If a responsible entity is found non-compliant, it shall keep information related to
the non-compliance until mitigation is complete and approved or for the time
specified above, whichever is longer.
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Check
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Page 3 of 8

FAC-002-2 3 — Facility Interconnection Studies

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

R1

Long-term
Planning

Medium The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities, but failed to
study one of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study two of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator studied
the reliability impact
of: (i) interconnecting
new generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of
generation,
transmission, or
electricity end-user
Facilities but failed to
study three of the Parts
(R1, 1.1-1.4).

The Transmission
Planner or Planning
Coordinator failed to
study the reliability
impact of:
interconnecting new
generation,
transmission, or
electricity end-user
Facilities, and (ii)
materially modifying
existing
interconnections of,
generation,
transmission, or
electricity end-user
Facilities.

R2

Long-term
Planning

Medium The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,
coordinated and
cooperated on studies

The Generator Owner
seeking to
interconnect new
generation Facilities,
or to materially
modify existing
interconnections of
generation Facilities,
coordinated and
cooperated on studies

The Generator Owner
seeking to interconnect
new generation
Facilities, or to
materially modify
existing
interconnections of
generation Facilities,
coordinated and
cooperated on studies

The Generator Owner
seeking to interconnect
new generation
Facilities, or to
materially modify
existing
interconnections of
generation Facilities,
failed to coordinate
and cooperate on

Page 4 of 8

FAC-002-2 3 — Facility Interconnection Studies

R3

Long-term
Planning

with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

with its Transmission
Planner or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

studies with its
Transmission Planner
or Planning
Coordinator.

Medium The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
one of the Parts (R1,
1.1-1.4).

The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
two of the Parts (R1,
1.1-1.4).

The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator, but failed
to provide data
necessary to perform
studies as described in
three of the Parts (R1,
1.1-1.4).

The Transmission
Owner, or Distribution
Provider, or LoadServing Entity seeking
to interconnect new
transmission Facilities
or electricity end-user
Facilities, or to
materially modify
existing
interconnections of
transmission Facilities
or electricity end-user
Facilities, failed to
coordinate and
cooperate on studies
with its Transmission
Planner or Planning
Coordinator.

Page 5 of 8

FAC-002-2 3 — Facility Interconnection Studies

R4

Long-term
Planning

Medium The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in one of the
Parts (R1, 1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in two of the
Parts (R1, 1.1-1.4).

The Transmission
Owner coordinated
and cooperated on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in three of
the Parts (R1, 1.1-1.4).

The Transmission
Owner failed to
coordinate and
cooperate on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested new or
materially modified
interconnections to its
Facilities.

R5

Long-term
Planning

Medium The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in one of the
Parts (R1, 1.1-1.4).

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in two of the
Parts (R1, 1.1-1.4).

The applicable
Generator Owner
coordinated and
cooperated on studies
with its Transmission
Planner or Planning
Coordinator regarding
requested
interconnections to its
Facilities, but failed to
provide data necessary
to perform studies as
described in three of
the Parts (R1, 1.1-1.4).

The applicable
Generator Owner
failed to coordinate
and cooperate on
studies with its
Transmission Planner
or Planning
Coordinator regarding
requested
interconnections to its
Facilities.

Page 6 of 8

FAC-002-2 3 — Facility Interconnection Studies

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None

Page 7 of 8

Application Guidelines
Guidelines and Technical Basis
Entities should have documentation to support the technical rationale for determining whether an
existing interconnection was “materially modified.” Recognizing that what constitutes a
“material modification” will vary from entity to entity, the intent is for this determination to be
based on engineering judgment.

Version History

Version

Date

Action

Change
Tracking

0

April 1, 2005

Effective Date

New

0

January 13, 2006

Removed duplication of “Regional
Reliability Organizations(s).

Errata

1

August 5, 2010

Modified to address Order No. 693
Directives contained in paragraph
693.
Adopted by the NERC Board of
Trustees.

Revised

1

February 7, 2013

1

November 21, 2013

R2 and associated elements approved
by NERC Board of Trustees for
retirement as part of the Paragraph 81
project (Project 2013-02) pending
applicable regulatory approval.
R2 and associated elements approved
by FERC for retirement as part of the
Paragraph 81 project (Project 201302)

2

Revisions to implement the
recommendations of the FAC FiveYear Review Team.

2

August 14, 2014

Adopted by the Board of Trustees.

2

November 6, 2014

FERC letter order issued approving
FAC-002-2.

3

Revision under
Project 2010-02

Adopted by the Board of Trustees.

Page 8 of 8

IRO-010-3 — Reliability Coordinator Data Specification and Collection

A. Introduction
1. Title:

Reliability Coordinator Data Specification and Collection

2. Number: IRO-010-3
3. Purpose: To prevent instability, uncontrolled separation, or Cascading outages that
adversely impact reliability, by ensuring the Reliability Coordinator has the data it needs
to monitor and assess the operation of its Reliability Coordinator Area.
4. Applicability
4.1. Reliability Coordinator.
4.2. Balancing Authority.
4.3. Generator Owner.
4.4. Generator Operator.
4.5. Transmission Operator.
4.6. Transmission Owner.
4.7. Distribution Provider.
5. Effective Date: See Implementation Plan.
B. Requirements
R1.

The Reliability Coordinator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include but not be limited to:
(Violation Risk Factor: Low) (Time Horizon: Operations Planning)
1.1.

A list of data and information needed by the Reliability Coordinator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data, as
deemed necessary by the Reliability Coordinator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

M1. The Reliability Coordinator shall make available its dated, current, in force
documented specification for data.
R2.

The Reliability Coordinator shall distribute its data specification to entities that have
data required by the Reliability Coordinator’s Operational Planning Analyses, Real-

Draft 2 of IRO-010-3
January 2020

Page 1 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

time monitoring, and Real-time Assessments. (Violation Risk Factor: Low) (Time
Horizon: Operations Planning)
M2. The Reliability Coordinator shall make available evidence that it has distributed its
data specification to entities that have data required by the Reliability Coordinator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments. This
evidence could include but is not limited to web postings with an electronic notice of
the posting, dated operator logs, voice recordings, postal receipts showing the
recipient, date and contents, or e-mail records.
R3.

Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R2 shall satisfy the obligations of the
documented specifications using: (Violation Risk Factor: Medium) (Time Horizon:
Operations Planning, Same-Day Operations, Real-time Operations)
3.1 A mutually agreeable format
3.2 A mutually agreeable process for resolving data conflicts
3.3 A mutually agreeable security protocol

M3. The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Reliability Coordinator, Transmission Operator, Transmission Owner, and
Distribution Provider receiving a data specification in Requirement R2 shall make
available evidence that it satisfied the obligations of the documented specification
using the specified criteria. Such evidence could include but is not limited to
electronic or hard copies of data transmittals or attestations of receiving entities.

Draft 2 of IRO-010-3
January 2020

Page 2 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

C. Compliance
1.

Compliance Monitoring Process
1.1.

Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2

Compliance Monitoring and Assessment Processes

As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment
Processes” refers to the identification of the processes that will be used to evaluate
data or information for the purpose of assessing performance or outcomes with the
associated reliability standard.
1.3.

Data Retention

The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
shall each keep data or evidence to show compliance as identified below unless
directed by its Compliance Enforcement Authority to retain specific evidence for a
longer period of time as part of an investigation:
The Reliability Coordinator shall retain its dated, current, in force documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments for Requirement R1,
Measure M1 as well as any documents in force since the last compliance audit.
The Reliability Coordinator shall keep evidence for three calendar years that it has
distributed its data specification to entities that have data required by the Reliability
Coordinator’s Operational Planning Analyses, Real-time monitoring, and Real-time
Assessments for Requirement R2, Measure M2.
Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
receiving a data specification shall retain evidence for the most recent 90-calendar
days that it has satisfied the obligations of the documented specifications in
accordance with Requirement R3 and Measurement M3.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.

Additional Compliance Information

None.

Draft 2 of IRO-010-3
January 2020

Page 3 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Table of Compliance Elements
R#

R1

Time
Horizon

VRF

Operations
Planning

Low

Violation Severity Levels
Lower

Moderate

High

Severe

The Reliability
Coordinator did not
include one of the
parts (Part 1.1 through
Part 1.4) of the
documented
specification for the
data necessary for it to
perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did
not include three
of the parts (Part
1.1 through Part
1.4) of the
documented
specification for
the data necessary
for it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did not
include any of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.
OR,
The Reliability
Coordinator did not
have a documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time

Draft 2 of IRO-010-3
January 2020

Page 4 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

R#

Time
Horizon

VRF

Violation Severity Levels
Lower

Moderate

High

Severe
monitoring, and
Real-time
Assessments.

For the Requirement R2 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to the
left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity has
just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R2

Operations
Planning

Draft 2 of IRO-010-3
January 2020

Low

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
one entity, or 5% or
less of the entities,
whichever is greater,
that have data
required by the
Reliability
Coordinator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
two entities, or more
than 5% and less
than or equal to 10%
of the reliability
entities, whichever is
greater, that have
data required by the
Reliability
Coordinator’s
Operational Planning
Analyses, and Realtime monitoring, and
Real-time

The Reliability
Coordinator did
not distribute its
data specification
as developed in
Requirement R1 to
three entities, or
more than 10%
and less than or
equal to 15% of the
reliability entities,
whichever is
greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
four or more
entities, or more
than 15% of the
entities, whichever
is greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time

Page 5 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

R#

R3

Time
Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

Draft 2 of IRO-010-3
January 2020

VRF

Violation Severity Levels
Lower

Medium

The responsible entity
receiving a data
specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for data
but failed to follow
one of the criteria
shown in Parts 3.1 –
3.3.

Moderate

High

Severe

Assessments.

monitoring, and
Real-time
Assessments.

Assessments.

The responsible
entity receiving a
data specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow two of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification
in Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow any of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification in
Requirement R2 did
not satisfy the
obligations of the
documented
specifications for
data.

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IRO-010-3 — Reliability Coordinator Data Specification and Collection

D. Regional Variances
None
E. Interpretations
None
F. Associated Documents
None
Version History
Version

Date

Action

Change Tracking

1

October 17, 2008

Adopted by Board of Trustees

New

1a

August 5, 2009

Added Appendix 1: Interpretation of
R1.2 and R3 as approved by Board of
Trustees

Addition

1a

March 17, 2011

Order issued by FERC approving IRO010-1a (approval effective 5/23/11)

1a
2

November 19, 2013 Updated VRFs based on June 24, 2013
approval
Revisions pursuant to Project 2014-03
April 2014

2

November 13, 2014

Adopted by NERC Board of Trustees

2

November 19, 2015

FERC approved IRO-010-2. Docket No.
RM15-16-000
Adopted by NERC Board of Trustees

3

Draft 2 of IRO-010-3
January 2020

Revisions under Project
2014-03

Page 7 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Guidelines and Technical Basis
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 adoption, the text from the rationale
text boxes was moved to this section.
Rationale for Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to result
in an appropriate level of situational awareness. Some examples include: 1) analyzing phase
angles which may result in the implementation of an Operating Plan to adjust generation or
curtail transactions so that a Transmission facility may be returned to service, or 2) evaluating
the impact of a modified Contingency resulting from the status change of a Special Protection
Scheme from enabled/in-service to disabled/out-of-service.
Rationale for Applicability Changes:
Changes were made to applicability based on IRO FYRT recommendation to address the need for
UVLS and UFLS information in the data specification.
The Interchange Authority was removed because activities in the Coordinate Interchange
standards are performed by software systems and not a responsible entity. The software, not a
functional entity, performs the task of accepting and disseminating interchange data between
entities. The Balancing Authority is the responsible functional entity for these tasks.
The Planning Coordinator and Transmission Planner were removed from Draft 2 as those entities
would not be involved in a data specification concept as outlined in this standard.
Rationale:
Proposed Requirement R1, Part 1.1:
Is in response to issues raised in NOPR paragraph 67 on the need for obtaining non-BES and
external network data necessary for the Reliability Coordinator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2:
Is in response to NOPR paragraph 78 on relay data.
Proposed Requirement R3, Part 3.3:

Draft 2 of IRO-010-3
January 2020

Page 8 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Is in response to NOPR paragraph 92 where concerns were raised about data exchange through
secured networks.
Corresponding changes have been made to proposed TOP-003-3.

Draft 2 of IRO-010-3
January 2020

Page 9 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

A. Introduction
1. Title:

Reliability Coordinator Data Specification and Collection

2. Number: IRO-010-3
3. Purpose: To prevent instability, uncontrolled separation, or Cascading outages that
adversely impact reliability, by ensuring the Reliability Coordinator has the data it needs
to monitor and assess the operation of its Reliability Coordinator Area.
4. Applicability
4.1. Reliability Coordinator.
4.2. Balancing Authority.
4.3. Generator Owner.
4.4. Generator Operator.
4.5. Transmission Operator.
4.6. Transmission Owner.
4.7. Distribution Provider.
5. Proposed Effective Date: See Implementation Plan.
B. Requirements
R1.

The Reliability Coordinator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include but not be limited to:
(Violation Risk Factor: Low) (Time Horizon: Operations Planning)
1.1.

A list of data and information needed by the Reliability Coordinator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data, as
deemed necessary by the Reliability Coordinator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

M1. The Reliability Coordinator shall make available its dated, current, in force
documented specification for data.
R2.

The Reliability Coordinator shall distribute its data specification to entities that have
data required by the Reliability Coordinator’s Operational Planning Analyses, Real-

Draft 1 2 of IRO-010-3
October January 20192020

Page 1 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

time monitoring, and Real-time Assessments. (Violation Risk Factor: Low) (Time
Horizon: Operations Planning)
M2. The Reliability Coordinator shall make available evidence that it has distributed its
data specification to entities that have data required by the Reliability Coordinator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments. This
evidence could include but is not limited to web postings with an electronic notice of
the posting, dated operator logs, voice recordings, postal receipts showing the
recipient, date and contents, or e-mail records.
R3.

Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R2 shall satisfy the obligations of the
documented specifications using: (Violation Risk Factor: Medium) (Time Horizon:
Operations Planning, Same-Day Operations, Real-time Operations)
3.1 A mutually agreeable format
3.2 A mutually agreeable process for resolving data conflicts
3.3 A mutually agreeable security protocol

M3. The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Reliability Coordinator, Transmission Operator, Transmission Owner, and
Distribution Provider receiving a data specification in Requirement R2 shall make
available evidence that it satisfied the obligations of the documented specification
using the specified criteria. Such evidence could include but is not limited to
electronic or hard copies of data transmittals or attestations of receiving entities.

Draft 1 2 of IRO-010-3
October January 20192020

Page 2 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

C. Compliance
1.

Compliance Monitoring Process
1.1.

Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2

Compliance Monitoring and Assessment Processes

As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment
Processes” refers to the identification of the processes that will be used to evaluate
data or information for the purpose of assessing performance or outcomes with the
associated reliability standard.
1.3.

Data Retention

The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
shall each keep data or evidence to show compliance as identified below unless
directed by its Compliance Enforcement Authority to retain specific evidence for a
longer period of time as part of an investigation:
The Reliability Coordinator shall retain its dated, current, in force documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments for Requirement R1,
Measure M1 as well as any documents in force since the last compliance audit.
The Reliability Coordinator shall keep evidence for three calendar years that it has
distributed its data specification to entities that have data required by the Reliability
Coordinator’s Operational Planning Analyses, Real-time monitoring, and Real-time
Assessments for Requirement R2, Measure M2.
Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Operator, Transmission Owner, and Distribution Provider
receiving a data specification shall retain evidence for the most recent 90-calendar
days that it has satisfied the obligations of the documented specifications in
accordance with Requirement R3 and Measurement M3.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.

Additional Compliance Information

None.

Draft 1 2 of IRO-010-3
October January 20192020

Page 3 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Table of Compliance Elements
R#

R1

Time
Horizon

VRF

Operations
Planning

Low

Violation Severity Levels
Lower

Moderate

High

Severe

The Reliability
Coordinator did not
include one of the
parts (Part 1.1 through
Part 1.4) of the
documented
specification for the
data necessary for it to
perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did
not include three
of the parts (Part
1.1 through Part
1.4) of the
documented
specification for
the data necessary
for it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did not
include any of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.
OR,
The Reliability
Coordinator did not
have a documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time

Draft 1 2 of IRO-010-3
October January 20192020

Page 4 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

R#

Time
Horizon

VRF

Violation Severity Levels
Lower

Moderate

High

Severe
monitoring, and
Real-time
Assessments.

For the Requirement R2 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to the
left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity has
just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R2

Operations
Planning

Draft 1 2 of IRO-010-3
October January 20192020

Low

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
one entity, or 5% or
less of the entities,
whichever is greater,
that have data
required by the
Reliability
Coordinator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
two entities, or more
than 5% and less
than or equal to 10%
of the reliability
entities, whichever is
greater, that have
data required by the
Reliability
Coordinator’s
Operational Planning
Analyses, and Realtime monitoring, and
Real-time

The Reliability
Coordinator did
not distribute its
data specification
as developed in
Requirement R1 to
three entities, or
more than 10%
and less than or
equal to 15% of the
reliability entities,
whichever is
greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
four or more
entities, or more
than 15% of the
entities, whichever
is greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time

Page 5 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

R#

R3

Time
Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

Draft 1 2 of IRO-010-3
October January 20192020

VRF

Violation Severity Levels
Lower

Medium

The responsible entity
receiving a data
specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for data
but failed to follow
one of the criteria
shown in Parts 3.1 –
3.3.

Moderate

High

Severe

Assessments.

monitoring, and
Real-time
Assessments.

Assessments.

The responsible
entity receiving a
data specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow two of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification
in Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow any of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification in
Requirement R2 did
not satisfy the
obligations of the
documented
specifications for
data.

Page 6 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

D. Regional Variances
None
E. Interpretations
None
F. Associated Documents
None
Version History
Version

Date

Action

Change Tracking

1

October 17, 2008

Adopted by Board of Trustees

New

1a

August 5, 2009

Added Appendix 1: Interpretation of
R1.2 and R3 as approved by Board of
Trustees

Addition

1a

March 17, 2011

Order issued by FERC approving IRO010-1a (approval effective 5/23/11)

1a
2

November 19, 2013 Updated VRFs based on June 24, 2013
approval
Revisions pursuant to Project 2014-03
April 2014

2

November 13, 2014

Adopted by NERC Board of Trustees

2

November 19, 2015

FERC approved IRO-010-2. Docket No.
RM15-16-000
Adopted by NERC Board of Trustees

3

Draft 1 2 of IRO-010-3
October January 20192020

Revisions under Project
2014-03

Page 7 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Guidelines and Technical Basis
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 adoption, the text from the rationale
text boxes was moved to this section.
Rationale for Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to result
in an appropriate level of situational awareness. Some examples include: 1) analyzing phase
angles which may result in the implementation of an Operating Plan to adjust generation or
curtail transactions so that a Transmission facility may be returned to service, or 2) evaluating
the impact of a modified Contingency resulting from the status change of a Special Protection
Scheme from enabled/in-service to disabled/out-of-service.
Rationale for Applicability Changes:
Changes were made to applicability based on IRO FYRT recommendation to address the need for
UVLS and UFLS information in the data specification.
The Interchange Authority was removed because activities in the Coordinate Interchange
standards are performed by software systems and not a responsible entity. The software, not a
functional entity, performs the task of accepting and disseminating interchange data between
entities. The Balancing Authority is the responsible functional entity for these tasks.
The Planning Coordinator and Transmission Planner were removed from Draft 2 as those entities
would not be involved in a data specification concept as outlined in this standard.
Rationale:
Proposed Requirement R1, Part 1.1:
Is in response to issues raised in NOPR paragraph 67 on the need for obtaining non-BES and
external network data necessary for the Reliability Coordinator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2:
Is in response to NOPR paragraph 78 on relay data.
Proposed Requirement R3, Part 3.3:

Draft 1 2 of IRO-010-3
October January 20192020

Page 8 of 9

IRO-010-3 — Reliability Coordinator Data Specification and Collection

Is in response to NOPR paragraph 92 where concerns were raised about data exchange through
secured networks.
Corresponding changes have been made to proposed TOP-003-3.

Draft 1 2 of IRO-010-3
October January 20192020

Page 9 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

A. Introduction
1. Title:

Reliability Coordinator Data Specification and Collection

2. Number: IRO-010-32
3. Purpose: To prevent instability, uncontrolled separation, or Cascading outages that
adversely impact reliability, by ensuring the Reliability Coordinator has the data it needs
to monitor and assess the operation of its Reliability Coordinator Area.
4. Applicability
4.1. Reliability Coordinator.
4.2. Balancing Authority.
4.3. Generator Owner.
4.4. Generator Operator.
4.5. Load-Serving Entity.
4.6.4.5.

Transmission Operator.

4.7.4.6.

Transmission Owner.

4.8.4.7.

Distribution Provider.

5. Proposed Effective Date: See Implementation Plan.
6. Background
See Project 2014-03 project page.
B. Requirements
R1.

The Reliability Coordinator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include but not be limited to:
(Violation Risk Factor: Low) (Time Horizon: Operations Planning)
1.1.

A list of data and information needed by the Reliability Coordinator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data, as
deemed necessary by the Reliability Coordinator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

Page 1 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

M1. The Reliability Coordinator shall make available its dated, current, in force
documented specification for data.
R2.

The Reliability Coordinator shall distribute its data specification to entities that have
data required by the Reliability Coordinator’s Operational Planning Analyses, Realtime monitoring, and Real-time Assessments. (Violation Risk Factor: Low) (Time
Horizon: Operations Planning)

M2. The Reliability Coordinator shall make available evidence that it has distributed its
data specification to entities that have data required by the Reliability Coordinator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments. This
evidence could include but is not limited to web postings with an electronic notice of
the posting, dated operator logs, voice recordings, postal receipts showing the
recipient, date and contents, or e-mail records.
R3.

Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Operator, Transmission Owner, and
Distribution Provider receiving a data specification in Requirement R2 shall satisfy the
obligations of the documented specifications using: (Violation Risk Factor: Medium)
(Time Horizon: Operations Planning, Same-Day Operations, Real-time Operations)
3.1 A mutually agreeable format
3.2 A mutually agreeable process for resolving data conflicts
3.3 A mutually agreeable security protocol

M3. The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Reliability Coordinator, Transmission Operator,
Transmission Owner, and Distribution Provider receiving a data specification in
Requirement R2 shall make available evidence that it satisfied the obligations of the
documented specification using the specified criteria. Such evidence could include
but is not limited to electronic or hard copies of data transmittals or attestations of
receiving entities.
C. Compliance
1.

Compliance Monitoring Process
1.1.

Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2

Compliance Monitoring and Assessment Processes

As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment
Processes” refers to the identification of the processes that will be used to evaluate

Page 2 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

data or information for the purpose of assessing performance or outcomes with the
associated reliability standard.
1.3.

Data Retention

The Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Operator, Transmission Owner, and
Distribution Provider shall each keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to retain
specific evidence for a longer period of time as part of an investigation:
The Reliability Coordinator shall retain its dated, current, in force documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments for Requirement R1,
Measure M1 as well as any documents in force since the last compliance audit.
The Reliability Coordinator shall keep evidence for three calendar years that it has
distributed its data specification to entities that have data required by the Reliability
Coordinator’s Operational Planning Analyses, Real-time monitoring, and Real-time
Assessments for Requirement R2, Measure M2.
Each Reliability Coordinator, Balancing Authority, Generator Owner, Generator
Operator, Interchange Authority, Load-Serving Entity, Transmission Operator,
Transmission Owner, and Distribution Provider receiving a data specification shall
retain evidence for the most recent 90-calendar days that it has satisfied the
obligations of the documented specifications in accordance with Requirement R3
and Measurement M3.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.

Additional Compliance Information

None.

Page 3 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

Table of Compliance Elements
R#

R1

Time
Horizon

VRF

Operations
Planning

Low

Violation Severity Levels
Lower

Moderate

High

Severe

The Reliability
Coordinator did not
include one of the
parts (Part 1.1 through
Part 1.4) of the
documented
specification for the
data necessary for it to
perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did
not include three
of the parts (Part
1.1 through Part
1.4) of the
documented
specification for
the data necessary
for it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.

The Reliability
Coordinator did not
include any of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time
Assessments.
OR,
The Reliability
Coordinator did not
have a documented
specification for the
data necessary for
it to perform its
Operational
Planning Analyses,
Real-time

Page 4 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

R#

Time
Horizon

VRF

Violation Severity Levels
Lower

Moderate

High

Severe
monitoring, and
Real-time
Assessments.

For the Requirement R2 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to the
left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity has
just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R2

Operations
Planning

Low

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
one entity, or 5% or
less of the entities,
whichever is greater,
that have data
required by the
Reliability
Coordinator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
two entities, or more
than 5% and less
than or equal to 10%
of the reliability
entities, whichever is
greater, that have
data required by the
Reliability
Coordinator’s
Operational Planning
Analyses, and Realtime monitoring, and
Real-time

The Reliability
Coordinator did
not distribute its
data specification
as developed in
Requirement R1 to
three entities, or
more than 10%
and less than or
equal to 15% of the
reliability entities,
whichever is
greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time

The Reliability
Coordinator did not
distribute its data
specification as
developed in
Requirement R1 to
four or more
entities, or more
than 15% of the
entities, whichever
is greater, that have
data required by
the Reliability
Coordinator’s
Operational
Planning Analyses,
Real-time
monitoring, and
Real-time

Page 5 of 9

Standard IRO-010-2 3 — Reliability Coordinator Data Specification and Collection

R#

R3

Time
Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

VRF

Violation Severity Levels
Lower

Medium

The responsible entity
receiving a data
specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for data
but failed to follow
one of the criteria
shown in Parts 3.1 –
3.3.

Moderate

High

Severe

Assessments.

monitoring, and
Real-time
Assessments.

Assessments.

The responsible
entity receiving a
data specification in
Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow two of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification
in Requirement R2
satisfied the
obligations of the
documented
specifications for
data but failed to
follow any of the
criteria shown in
Parts 3.1 – 3.3.

The responsible
entity receiving a
data specification in
Requirement R2 did
not satisfy the
obligations of the
documented
specifications for
data.

Page 6 of 9

IRO-010-3 — Reliability Coordinator Data Specification and CollectionStandard IRO-010-2
— Guidelines and Technical Basis

D. Regional Variances
None
E. Interpretations
None
F. Associated Documents
None
Version History
Version

Date

Action

Change Tracking

1

October 17, 2008

Adopted by Board of Trustees

New

1a

August 5, 2009

Added Appendix 1: Interpretation of
R1.2 and R3 as approved by Board of
Trustees

Addition

1a

March 17, 2011

Order issued by FERC approving IRO010-1a (approval effective 5/23/11)

1a
2

November 19, 2013 Updated VRFs based on June 24, 2013
approval
Revisions pursuant to Project 2014-03
April 2014

2

November 13, 2014

Adopted by NERC Board of Trustees

2

November 19, 2015

FERC approved IRO-010-2. Docket No.
RM15-16-000
Adopted by NERC Board of Trustees

3

Revisions under Project
2014-03

Page 7 of 9

IRO-010-3 — Reliability Coordinator Data Specification and CollectionStandard IRO-010-2
— Guidelines and Technical Basis

Guidelines and Technical Basis
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 adoption, the text from the rationale
text boxes was moved to this section.
Rationale for Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to result
in an appropriate level of situational awareness. Some examples include: 1) analyzing phase
angles which may result in the implementation of an Operating Plan to adjust generation or
curtail transactions so that a Transmission facility may be returned to service, or 2) evaluating
the impact of a modified Contingency resulting from the status change of a Special Protection
Scheme from enabled/in-service to disabled/out-of-service.
Rationale for Applicability Changes:
Changes were made to applicability based on IRO FYRT recommendation to address the need for
UVLS and UFLS information in the data specification.
The Interchange Authority was removed because activities in the Coordinate Interchange
standards are performed by software systems and not a responsible entity. The software, not a
functional entity, performs the task of accepting and disseminating interchange data between
entities. The Balancing Authority is the responsible functional entity for these tasks.
The Planning Coordinator and Transmission Planner were removed from Draft 2 as those entities
would not be involved in a data specification concept as outlined in this standard.
Rationale:
Proposed Requirement R1, Part 1.1:
Is in response to issues raised in NOPR paragraph 67 on the need for obtaining non-BES and
external network data necessary for the Reliability Coordinator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2:
Is in response to NOPR paragraph 78 on relay data.
Proposed Requirement R3, Part 3.3:
Page 8 of 9

IRO-010-3 — Reliability Coordinator Data Specification and CollectionStandard IRO-010-2
— Guidelines and Technical Basis

Is in response to NOPR paragraph 92 where concerns were raised about data exchange through
secured networks.
Corresponding changes have been made to proposed TOP-003-3.

Page 9 of 9

MOD-031-3 — Demand and Energy Data

A. Introduction
Title: Demand and Energy Data
Number:

MOD-031-3

Purpose:
To provide authority for applicable entities to collect Demand, energy
and related data to support reliability studies and assessments and to enumerate the
responsibilities and obligations of requestors and respondents of that data.
Applicability:
1.1. Functional Entities:
1.1.1 Planning Coordinator
1.1.2 Transmission Planner
1.1.3 Balancing Authority
1.1.4 Resource Planner
1.1.5 Distribution Provider
2.

Effective Date: See Implementation Plan.

B. Requirements and Measures
R1.

Each Planning Coordinator or Balancing Authority that identifies a need for the
collection of Total Internal Demand, Net Energy for Load, and Demand Side
Management data shall develop and issue a data request to the applicable entities in
its area. The data request shall include: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
1.1. A list of Transmission Planners, Balancing Authorities, and Distribution Providers
that are required to provide the data (“Applicable Entities”).
1.2. A timetable for providing the data. (A minimum of 30 calendar days must be
allowed for responding to the request).
1.3. A request to provide any or all of the following actual data, as necessary:
1.3.1. Integrated hourly Demands in megawatts for the prior calendar year.
1.3.2. Monthly and annual integrated peak hour Demands in megawatts for the
prior calendar year.
1.3.2.1.

Draft 2 of MOD-031-3
January 2020

If the annual peak hour actual Demand varies due to weatherrelated conditions (e.g., temperature, humidity or wind
speed), the Applicable Entity shall also provide the weather
normalized annual peak hour actual Demand for the prior
calendar year.

Page 1 of 11

MOD-031-3 — Demand and Energy Data

1.3.3. Monthly and annual Net Energy for Load in gigawatt hours for the prior
calendar year.
1.3.4. Monthly and annual peak hour controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator in megawatts for the prior calendar year. Three values shall be
reported for each hour: 1) the committed megawatts (the amount under
control or supervision), 2) the dispatched megawatts (the amount, if any,
activated for use by the System Operator), and 3) the realized megawatts
(the amount of actual demand reduction).
1.4. A request to provide any or all of the following forecast data, as necessary:
1.4.1. Monthly peak hour forecast Total Internal Demands in megawatts for the
next two calendar years.
1.4.2. Monthly forecast Net Energy for Load in gigawatthours for the next two
calendar years.
1.4.3. Peak hour forecast Total Internal Demands (summer and winter) in
megawatts for ten calendar years into the future.
1.4.4. Annual forecast Net Energy for Load in gigawatthours for ten calendar
years into the future.
1.4.5. Total and available peak hour forecast of controllable and dispatchable
Demand Side Management (summer and winter), in megawatts, under
the control or supervision of the System Operator for ten calendar years
into the future.
1.5. A request to provide any or all of the following summary explanations, as
necessary,:
1.5.1. The assumptions and methods used in the development of aggregated
Peak Demand and Net Energy for Load forecasts.
1.5.2. The Demand and energy effects of controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator.
1.5.3. How Demand Side Management is addressed in the forecasts of its Peak
Demand and annual Net Energy for Load.
1.5.4. How the controllable and dispatchable Demand Side Management
forecast compares to actual controllable and dispatchable Demand Side
Management for the prior calendar year and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
1.5.5. How the peak Demand forecast compares to actual Demand for the prior
calendar year with due regard to any relevant weather-related variations

Draft 2 of MOD-031-3
January 2020

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MOD-031-3 — Demand and Energy Data

(e.g., temperature, humidity, or wind speed) and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
M1. The Planning Coordinator or Balancing Authority shall have a dated data request,
either in hardcopy or electronic format, in accordance with Requirement R1.
R2.

Each Applicable Entity identified in a data request shall provide the data requested by
its Planning Coordinator or Balancing Authority in accordance with the data request
issued pursuant to Requirement R1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

M2. Each Applicable Entity shall have evidence, such as dated e-mails or dated transmittal
letters that it provided the requested data in accordance with Requirement R2.
R3.

The Planning Coordinator or the Balancing Authority shall provide the data listed
under Requirement R1 Parts 1.3 through 1.5 for their area to the applicable Regional
Entity within 75 calendar days of receiving a request for such data, unless otherwise
agreed upon by the parties. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]

M3. Each Planning Coordinator or Balancing Authority, shall have evidence, such as dated
e-mails or dated transmittal letters that it provided the data requested by the
applicable Regional Entity in accordance with Requirement R3.
R4.

Any Applicable Entity shall, in response to a written request for the data included in
parts 1.3-1.5 of Requirement R1 from a Planning Coordinator, Balancing Authority,
Transmission Planner or Resource Planner with a demonstrated need for such data in
order to conduct reliability assessments of the Bulk Electric System, provide or
otherwise make available that data to the requesting entity. This requirement does
not modify an entity’s obligation pursuant to Requirement R2 to respond to data
requests issued by its Planning Coordinator or Balancing Authority pursuant to
Requirement R1. Unless otherwise agreed upon, the Applicable Entity: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
•

shall not be required to alter the format in which it maintains or uses the data;

•

shall provide the requested data within 45 calendar days of the written
request, subject to part 4.1 of this requirement; unless providing the
requested data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements

4.1. If the Applicable Entity does not provide data requested because (1) the
requesting entity did not demonstrate a reliability need for the data; or (2)
providing the data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements, the Applicable Entity shall, within 30
calendar days of the written request, provide a written response to the
requesting entity specifying the data that is not being provided and on what
basis.

Draft 2 of MOD-031-3
January 2020

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MOD-031-3 — Demand and Energy Data

M4. Each Applicable Entity identified in Requirement R4 shall have evidence such as dated
e-mails or dated transmittal letters that it provided the data requested or provided a
written response specifying the data that is not being provided and the basis for not
providing the data in accordance with Requirement R4.

Draft 2 of MOD-031-3
January 2020

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MOD-031-3 — Demand and Energy Data

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The Applicable Entity shall keep data or evidence to show compliance with
Requirements R1 through R4, and Measures M1 through M4, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an Applicable Entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Draft 2 of MOD-031-3
January 2020

Page 5 of 11

MOD-031-3 — Demand and Energy Data

Table of Compliance Elements
R#

Time Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

N/A

N/A

N/A

The Planning Coordinator
or Balancing Authority
developed and issued a
data request but failed to
include either the entity(s)
necessary to provide the
data or the timetable for
providing the data.

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.3.1 through part
1.3.4

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.4.1 through part
1.4.5

R1

Long-term
Planning

Medium

R2

Long-term
Planning

Medium The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide all of the
data requested in
Requirement R1 part
1.5.1 through part
1.5.5

Draft 2 of MOD-031-3
January 2020

High VSL

Severe VSL

OR

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MOD-031-3 — Demand and Energy Data

did so after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 6 days
after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

R3

Long-term
Planning

Draft 2 of MOD-031-3
January 2020

Medium The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 75 days

1.4.1 through part
1.4.5

1.4.1 through part
1.4.5

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but
did so 6 days after the
date indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 11
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Applicable Entity, as
defined in the data request
The Applicable Entity, developed in Requirement
R1, failed to provide the
as defined in the data
data requested in the
request developed in
timetable provided
Requirement R1,
pursuant to Requirement
provided the data
R1 prior to 16 days after
requested in
the date indicated in the
Requirement R1, but
timetable provided
did so 11 days after
pursuant to Requirement
the date indicated in
the timetable provided R1 part 1.2.
pursuant to
Requirement R1 part
1.2 but prior to 15
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 80 days

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 85 days

The Planning Coordinator
or Balancing Authority, in
response to a request by
the Regional Entity, failed
to make available the data
requested prior to 91 days

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MOD-031-3 — Demand and Energy Data

R4

Long-term
Planning

Draft 2 of MOD-031-3
January 2020

from the date of
request but prior to 81
days from the date of
the request.

from the date of
request but prior to 86
days from the date of
the request.

from the date of
request but prior to 91
days from the date of
the request.

or more from the date of
the request.

Medium The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
45 days from the date
of request but prior to
51 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
50 days from the date
of request but prior to
56 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
55 days from the date
of request but prior to
61 days from the date
of the request

The Applicable Entity failed
to provide or otherwise
make available the data to
the requesting entity
within 60 days from the
date of the request

OR

OR

OR

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 30 days of the
written request but
prior to 36 days of the
written request.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 35 days of the
written request but
prior to 41 days of the
written request.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 40 days of the
written request but
prior to 46 days of the
written request.

OR
The Applicable Entity that
is not providing the data
requested failed to provide
a written response
specifying the data that is
not being provided and on
what basis within 45 days
of the written request.

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MOD-031-3 — Demand and Energy Data

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

Action

1

May 6, 2014

1

February 19,
2015

Adopted by the NERC Board
of Trustees
FERC order approving MOD031-1

2

November 5,
2015

Adopted by the NERC Board
of Trustees

2

February 18,
2016

FERC order approving MOD031-2. Docket No. RD16-1000

3

Draft 2 of MOD-031-3
January 2020

Change Tracking

Adopted by the NERC Board
of Trustees

Page 9 of 11

MOD-031-3 — Demand and Energy Data

Guidelines and Technical Basis
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:
Rationale for R1: To ensure that when Planning Coordinators (PCs) or Balancing Authorities
(BAs) request data (R1), they identify the entities that must provide the data (Applicable Entity
in part 1.1), the data to be provided (parts 1.3 – 1.5) and the due dates (part 1.2) for the
requested data.
For Requirement R1 part 1.3.2.1, if the Demand does not vary due to weather-related
conditions (e.g., temperature, humidity or wind speed), or the weather assumed in the forecast
was the same as the actual weather, the weather normalized actual Demand will be the same
as the actual demand reported for Requirement R1 part 1.3.2. Otherwise the annual peak hour
weather normalized actual Demand will be different from the actual demand reported for
Requirement R1 part 1.3.2.
Balancing Authorities are included here to reflect a practice in the WECC Region where BAs are
the entity that perform this requirement in lieu of the PC.
Rationale for R2:
This requirement will ensure that entities identified in Requirement R1, as responsible for
providing data, provide the data in accordance with the details described in the data request
developed in accordance with Requirement R1. In no event shall the Applicable Entity be
required to provide data under this requirement that is outside the scope of parts 1.3 - 1.5 of
Requirement R1.
Rationale for R3:
This requirement will ensure that the Planning Coordinator or when applicable, the Balancing
Authority, provides the data requested by the Regional Entity.
Rationale for R4:
This requirement will ensure that the Applicable Entity will make the data requested by the
Planning Coordinator or Balancing Authority in Requirement R1 available to other applicable
entities (Planning Coordinator, Balancing Authority, Transmission Planner or Resource Planner)
unless providing the data would conflict with the Applicable Entity’s confidentiality, regulatory,
or security requirements. The sharing of documentation of the supporting methods and
assumptions used to develop forecasts as well as information-sharing activities will improve the
efficiency of planning practices and support the identification of needed system
reinforcements.

Draft 2 of MOD-031-3
January 2020

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MOD-031-3 — Demand and Energy Data

The obligation to share data under Requirement R4 does not supersede or otherwise modify
any of the Applicable Entity’s existing confidentiality obligations. For instance, if an entity is
prohibited from providing any of the requested data pursuant to confidentiality provisions of an
Open Access Transmission Tariff or a contractual arrangement, Requirement R4 does not
require the Applicable Entity to provide the data to a requesting entity. Rather, under Part 4.1,
the Applicable Entity must simply provide written notification to the requesting entity that it
will not be providing the data and the basis for not providing the data. If the Applicable Entity is
subject to confidentiality obligations that allow the Applicable Entity to share the data only if
certain conditions are met, the Applicable Entity shall ensure that those conditions are met
within the 45-day time period provided in Requirement R4, communicate with the requesting
entity regarding an extension of the 45-day time period so as to meet all those conditions, or
provide justification under Part 4.1 as to why those conditions cannot be met under the
circumstances.

Draft 2 of MOD-031-3
January 2020

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MOD-031-3 — Demand and Energy Data

A. Introduction
Title: Demand and Energy Data
Number:

MOD-031-3

Purpose:
To provide authority for applicable entities to collect Demand, energy
and related data to support reliability studies and assessments and to enumerate the
responsibilities and obligations of requestors and respondents of that data.
Applicability:
1.1. Functional Entities:
1.1.1 Planning Coordinator
1.1.2 Transmission Planner
1.1.3 Balancing Authority
1.1.4 Resource Planner
1.1.5 Distribution Provider
1.2. Effective Date: See Implementation Plan.
To ensure that various forms of historical and forecast Demand and energy data and
information is available to the parties that perform reliability studies and
assessments, authority is needed to collect the applicable data.
The collection of Demand, Net Energy for Load and Demand Side Management data
requires coordination and collaboration between Planning Coordinators, Transmission
and Resource Planners, and Distribution Providers. Ensuring that planners and
operators have access to complete and accurate load forecasts – as well as the
supporting methods and assumptions used to develop these forecasts – enhances the
reliability of the Bulk Electric System. Consistent documenting and information
sharing activities will also improve efficient planning practices and support the
identification of needed system reinforcements. Furthermore, collection of actual
Demand and Demand Side Management performance during the prior year will allow
for comparison to prior forecasts and further contribute to enhanced accuracy of load
forecasting practices.
Data provided under this standard is generally considered confidential by Planning
Coordinators and Balancing Authorities receiving the data. Furthermore, data
reported to a Regional Entity is subject to the confidentiality provisions in Section
1500 of the North American Electric Reliability Corporation Rules of Procedure and is
typically aggregated with data of other functional entities in a non-attributable
manner. While this standard allows for the sharing of data necessary to perform
certain reliability studies and assessments, any data received under this standard for
which an applicable entity has made a claim of confidentiality should be maintained
as confidential by the receiving entity.

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MOD-031-3 — Demand and Energy Data

B. Requirements and Measures
R1.

Each Planning Coordinator or Balancing Authority that identifies a need for the
collection of Total Internal Demand, Net Energy for Load, and Demand Side
Management data shall develop and issue a data request to the applicable entities in
its area. The data request shall include: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
1.1. A list of Transmission Planners, Balancing Authorities, and Distribution Providers
that are required to provide the data (“Applicable Entities”).
1.2. A timetable for providing the data. (A minimum of 30 calendar days must be
allowed for responding to the request).
1.3. A request to provide any or all of the following actual data, as necessary:
1.3.1. Integrated hourly Demands in megawatts for the prior calendar year.
1.3.2. Monthly and annual integrated peak hour Demands in megawatts for the
prior calendar year.
1.3.2.1.

If the annual peak hour actual Demand varies due to weatherrelated conditions (e.g., temperature, humidity or wind
speed), the Applicable Entity shall also provide the weather
normalized annual peak hour actual Demand for the prior
calendar year.

1.3.3. Monthly and annual Net Energy for Load in gigawatthours for the prior
calendar year.
1.3.4. Monthly and annual peak hour controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator in megawatts for the prior calendar year. Three values shall be
reported for each hour: 1) the committed megawatts (the amount under
control or supervision), 2) the dispatched megawatts (the amount, if any,
activated for use by the System Operator), and 3) the realized megawatts
(the amount of actual demand reduction).
1.4. A request to provide any or all of the following forecast data, as necessary:
1.4.1. Monthly peak hour forecast Total Internal Demands in megawatts for the
next two calendar years.
1.4.2. Monthly forecast Net Energy for Load in gigawatthours for the next two
calendar years.
1.4.3. Peak hour forecast Total Internal Demands (summer and winter) in
megawatts for ten calendar years into the future.
1.4.4. Annual forecast Net Energy for Load in gigawatthours for ten calendar
years into the future.

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MOD-031-3 — Demand and Energy Data

1.4.5. Total and available peak hour forecast of controllable and dispatchable
Demand Side Management (summer and winter), in megawatts, under
the control or supervision of the System Operator for ten calendar years
into the future.
1.5. A request to provide any or all of the following summary explanations, as
necessary,:
1.5.1. The assumptions and methods used in the development of aggregated
Peak Demand and Net Energy for Load forecasts.
1.5.2. The Demand and energy effects of controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator.
1.5.3. How Demand Side Management is addressed in the forecasts of its Peak
Demand and annual Net Energy for Load.
1.5.4. How the controllable and dispatchable Demand Side Management
forecast compares to actual controllable and dispatchable Demand Side
Management for the prior calendar year and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
1.5.5. How the peak Demand forecast compares to actual Demand for the prior
calendar year with due regard to any relevant weather-related variations
(e.g., temperature, humidity, or wind speed) and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
M1. The Planning Coordinator or Balancing Authority shall have a dated data request,
either in hardcopy or electronic format, in accordance with Requirement R1.
R2.

Each Applicable Entity identified in a data request shall provide the data requested by
its Planning Coordinator or Balancing Authority in accordance with the data request
issued pursuant to Requirement R1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

M2. Each Applicable Entity shall have evidence, such as dated e-mails or dated transmittal
letters that it provided the requested data in accordance with Requirement R2.
R3.

The Planning Coordinator or the Balancing Authority shall provide the data listed
under Requirement R1 Parts 1.3 through 1.5 for their area to the applicable Regional
Entity within 75 calendar days of receiving a request for such data, unless otherwise
agreed upon by the parties. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]

M3. Each Planning Coordinator or Balancing Authority, shall have evidence, such as dated
e-mails or dated transmittal letters that it provided the data requested by the
applicable Regional Entity in accordance with Requirement R3.
R4.

Any Applicable Entity shall, in response to a written request for the data included in
parts 1.3-1.5 of Requirement R1 from a Planning Coordinator, Balancing Authority,

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MOD-031-3 — Demand and Energy Data

Transmission Planner or Resource Planner with a demonstrated need for such data in
order to conduct reliability assessments of the Bulk Electric System, provide or
otherwise make available that data to the requesting entity. This requirement does
not modify an entity’s obligation pursuant to Requirement R2 to respond to data
requests issued by its Planning Coordinator or Balancing Authority pursuant to
Requirement R1. Unless otherwise agreed upon, the Applicable Entity: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
•

shall not be required to alter the format in which it maintains or uses the data;

•

shall provide the requested data within 45 calendar days of the written
request, subject to part 4.1 of this requirement; unless providing the
requested data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements

4.1. If the Applicable Entity does not provide data requested because (1) the
requesting entity did not demonstrate a reliability need for the data; or (2)
providing the data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements, the Applicable Entity shall, within 30
calendar days of the written request, provide a written response to the
requesting entity specifying the data that is not being provided and on what
basis.
M4. Each Applicable Entity identified in Requirement R4 shall have evidence such as dated
e-mails or dated transmittal letters that it provided the data requested or provided a
written response specifying the data that is not being provided and the basis for not
providing the data in accordance with Requirement R4.

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MOD-031-3 — Demand and Energy Data

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The Applicable Entity shall keep data or evidence to show compliance with
Requirements R1 through R4, and Measures M1 through M4, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an Applicable Entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

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MOD-031-3 — Demand and Energy Data

Table of Compliance Elements
R#

Time Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

N/A

N/A

N/A

The Planning Coordinator
or Balancing Authority
developed and issued a
data request but failed to
include either the entity(s)
necessary to provide the
data or the timetable for
providing the data.

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.3.1 through part
1.3.4

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.4.1 through part
1.4.5

R1

Long-term
Planning

Medium

R2

Long-term
Planning

Medium The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide all of the
data requested in
Requirement R1 part
1.5.1 through part
1.5.5

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High VSL

Severe VSL

OR

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MOD-031-3 — Demand and Energy Data

did so after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 6 days
after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

R3

Long-term
Planning

Medium The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 75 days

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October DecemberJanuary 201920

1.4.1 through part
1.4.5

1.4.1 through part
1.4.5

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but
did so 6 days after the
date indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 11
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Applicable Entity, as
defined in the data request
The Applicable Entity, developed in Requirement
R1, failed to provide the
as defined in the data
data requested in the
request developed in
timetable provided
Requirement R1,
pursuant to Requirement
provided the data
R1 prior to 16 days after
requested in
the date indicated in the
Requirement R1, but
timetable provided
did so 11 days after
pursuant to Requirement
the date indicated in
the timetable provided R1 part 1.2.
pursuant to
Requirement R1 part
1.2 but prior to 15
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 80 days

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 85 days

The Planning Coordinator
or Balancing Authority, in
response to a request by
the Regional Entity, failed
to make available the data
requested prior to 91 days

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MOD-031-3 — Demand and Energy Data

R4

Long-term
Planning

from the date of
request but prior to 81
days from the date of
the request.

from the date of
request but prior to 86
days from the date of
the request.

from the date of
request but prior to 91
days from the date of
the request.

or more from the date of
the request.

Medium The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
45 days from the date
of request but prior to
51 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
50 days from the date
of request but prior to
56 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
55 days from the date
of request but prior to
61 days from the date
of the request

The Applicable Entity failed
to provide or otherwise
make available the data to
the requesting entity
within 60 days from the
date of the request

OR

OR

OR

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 30 days of the
written request but
prior to 36 days of the
written resquest.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 35 days of the
written request but
prior to 41 days of the
written resquest.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 40 days of the
written request but
prior to 46 days of the
written resquest.

Draft 1 2 of MOD-031-3
October DecemberJanuary 201920

OR
The Applicable Entity that
is not providing the data
requested failed to provide
a written response
specifying the data that is
not being provided and on
what basis within 45 days
of the written resquest.

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MOD-031-3 — Demand and Energy Data

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

Action

1

May 6, 2014

1

February 19,
2015

Adopted by the NERC Board
of Trustees
FERC order approving MOD031-1

2

November 5,
2015

Adopted by the NERC Board
of Trustees

2

February 18,
2016

FERC order approving MOD031-2. Docket No. RD16-1000

3

Draft 1 2 of MOD-031-3
October DecemberJanuary 201920

Change Tracking

Adopted by the NERC Board
of Trustees

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MOD-031-3 — Demand and Energy Data - Application Guidelines

Guidelines and Technical Basis
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:
Rationale for R1: To ensure that when Planning Coordinators (PCs) or Balancing Authorities
(BAs) request data (R1), they identify the entities that must provide the data (Applicable Entity
in part 1.1), the data to be provided (parts 1.3 – 1.5) and the due dates (part 1.2) for the
requested data.
For Requirement R1 part 1.3.2.1, if the Demand does not vary due to weather-related
conditions (e.g., temperature, humidity or wind speed), or the weather assumed in the forecast
was the same as the actual weather, the weather normalized actual Demand will be the same
as the actual demand reported for Requirement R1 part 1.3.2. Otherwise the annual peak hour
weather normalized actual Demand will be different from the actual demand reported for
Requirement R1 part 1.3.2.
Balancing Authorities are included here to reflect a practice in the WECC Region where BAs are
the entity that perform this requirement in lieu of the PC.
Rationale for R2:
This requirement will ensure that entities identified in Requirement R1, as responsible for
providing data, provide the data in accordance with the details described in the data request
developed in accordance with Requirement R1. In no event shall the Applicable Entity be
required to provide data under this requirement that is outside the scope of parts 1.3 - 1.5 of
Requirement R1.
Rationale for R3:
This requirement will ensure that the Planning Coordinator or when applicable, the Balancing
Authority, provides the data requested by the Regional Entity.
Rationale for R4:
This requirement will ensure that the Applicable Entity will make the data requested by the
Planning Coordinator or Balancing Authority in Requirement R1 available to other applicable
entities (Planning Coordinator, Balancing Authority, Transmission Planner or Resource Planner)
unless providing the data would conflict with the Applicable Entity’s confidentiality, regulatory,
or security requirements. The sharing of documentation of the supporting methods and
assumptions used to develop forecasts as well as information-sharing activities will improve the
efficiency of planning practices and support the identification of needed system
reinforcements.

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MOD-031-3 — Demand and Energy Data - Application Guidelines

The obligation to share data under Requirement R4 does not supersede or otherwise modify
any of the Applicable Entity’s existing confidentiality obligations. For instance, if an entity is
prohibited from providing any of the requested data pursuant to confidentiality provisions of an
Open Access Transmission Tariff or a contractual arrangement, Requirement R4 does not
require the Applicable Entity to provide the data to a requesting entity. Rather, under Part 4.1,
the Applicable Entity must simply provide written notification to the requesting entity that it
will not be providing the data and the basis for not providing the data. If the Applicable Entity is
subject to confidentiality obligations that allow the Applicable Entity to share the data only if
certain conditions are met, the Applicable Entity shall ensure that those conditions are met
within the 45-day time period provided in Requirement R4, communicate with the requesting
entity regarding an extension of the 45-day time period so as to meet all those conditions, or
provide justification under Part 4.1 as to why those conditions cannot be met under the
circumstances.

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MOD-031-2 3 — Demand and Energy Data

A. Introduction
1.

Title: Demand and Energy Data

2.

Number:

3.

Purpose: To provide authority for applicable entities to collect Demand, energy
and related data to support reliability studies and assessments and to enumerate the
responsibilities and obligations of requestors and respondents of that data.

4.

Applicability:

MOD-031-23

4.1. Functional Entities:
4.1.1 Planning Authority and Planning Coordinator (hereafter collectively
referred to as the “Planning Coordinator”)
4.1.24.1.1
This proposed standard combines “Planning Authority” with
“Planning Coordinator” in the list of applicable functional entities. The
NERC Functional Model lists “Planning Coordinator” while the
registration criteria list “Planning Authority,” and they are not yet
synchronized. Until that occurs, the proposed standard applies to both
“Planning Authority” and “Planning Coordinator.”
4.1.34.1.2

Transmission Planner

4.1.44.1.3

Balancing Authority

4.1.54.1.4

Resource Planner

4.1.6 Load-Serving Entity
4.1.74.1.5

Distribution Provider

5.

Effective Date: See the MOD-031-2 Implementation Plan.

6.

Background:
To ensure that various forms of historical and forecast Demand and energy data and
information is available to the parties that perform reliability studies and
assessments, authority is needed to collect the applicable data.
The collection of Demand, Net Energy for Load and Demand Side Management data
requires coordination and collaboration between Planning Authorities (Planning
Coordinators), Transmission and Resource Planners, Load-Serving Entities and
Distribution Providers. Ensuring that planners and operators have access to complete
and accurate load forecasts – as well as the supporting methods and assumptions
used to develop these forecasts – enhances the reliability of the Bulk Electric System.
Consistent documenting and information sharing activities will also improve efficient
planning practices and support the identification of needed system reinforcements.
Furthermore, collection of actual Demand and Demand Side Management
performance during the prior year will allow for comparison to prior forecasts and
further contribute to enhanced accuracy of load forecasting practices.

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MOD-031-2 3 — Demand and Energy Data

Data provided under this standard is generally considered confidential by Planning
Coordinators and Balancing Authorities receiving the data. Furthermore, data
reported to a Regional Entity is subject to the confidentiality provisions in Section
1500 of the North American Electric Reliability Corporation Rules of Procedure and is
typically aggregated with data of other functional entities in a non-attributable
manner. While this standard allows for the sharing of data necessary to perform
certain reliability studies and assessments, any data received under this standard for
which an applicable entity has made a claim of confidentiality should be maintained
as confidential by the receiving entity.
B. Requirements and Measures
R1.

Each Planning Coordinator or Balancing Authority that identifies a need for the
collection of Total Internal Demand, Net Energy for Load, and Demand Side
Management data shall develop and issue a data request to the applicable entities in
its area. The data request shall include: [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]
1.1. A list of Transmission Planners, Balancing Authorities, Load Serving Entities, and
Distribution Providers that are required to provide the data (“Applicable
Entities”).
1.2. A timetable for providing the data. (A minimum of 30 calendar days must be
allowed for responding to the request).
1.3. A request to provide any or all of the following actual data, as necessary:
1.3.1. Integrated hourly Demands in megawatts for the prior calendar year.
1.3.2. Monthly and annual integrated peak hour Demands in megawatts for the
prior calendar year.
1.3.2.1.

If the annual peak hour actual Demand varies due to weatherrelated conditions (e.g., temperature, humidity or wind
speed), the Applicable Entity shall also provide the weather
normalized annual peak hour actual Demand for the prior
calendar year.

1.3.3. Monthly and annual Net Energy for Load in gigawatthours for the prior
calendar year.
1.3.4. Monthly and annual peak hour controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator in megawatts for the prior calendar year. Three values shall be
reported for each hour: 1) the committed megawatts (the amount under
control or supervision), 2) the dispatched megawatts (the amount, if any,
activated for use by the System Operator), and 3) the realized megawatts
(the amount of actual demand reduction).

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MOD-031-2 3 — Demand and Energy Data

1.4. A request to provide any or all of the following forecast data, as necessary:
1.4.1. Monthly peak hour forecast Total Internal Demands in megawatts for the
next two calendar years.
1.4.2. Monthly forecast Net Energy for Load in gigawatthours for the next two
calendar years.
1.4.3. Peak hour forecast Total Internal Demands (summer and winter) in
megawatts for ten calendar years into the future.
1.4.4. Annual forecast Net Energy for Load in gigawatthours for ten calendar
years into the future.
1.4.5. Total and available peak hour forecast of controllable and dispatchable
Demand Side Management (summer and winter), in megawatts, under
the control or supervision of the System Operator for ten calendar years
into the future.
1.5. A request to provide any or all of the following summary explanations, as
necessary,:
1.5.1. The assumptions and methods used in the development of aggregated
Peak Demand and Net Energy for Load forecasts.
1.5.2. The Demand and energy effects of controllable and dispatchable Demand
Side Management under the control or supervision of the System
Operator.
1.5.3. How Demand Side Management is addressed in the forecasts of its Peak
Demand and annual Net Energy for Load.
1.5.4. How the controllable and dispatchable Demand Side Management
forecast compares to actual controllable and dispatchable Demand Side
Management for the prior calendar year and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
1.5.5. How the peak Demand forecast compares to actual Demand for the prior
calendar year with due regard to any relevant weather-related variations
(e.g., temperature, humidity, or wind speed) and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
M1. The Planning Coordinator or Balancing Authority shall have a dated data request,
either in hardcopy or electronic format, in accordance with Requirement R1.
R2.

Each Applicable Entity identified in a data request shall provide the data requested by
its Planning Coordinator or Balancing Authority in accordance with the data request
issued pursuant to Requirement R1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

M2. Each Applicable Entity shall have evidence, such as dated e-mails or dated transmittal
letters that it provided the requested data in accordance with Requirement R2.

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MOD-031-2 3 — Demand and Energy Data

R3.

The Planning Coordinator or the Balancing Authority shall provide the data listed
under Requirement R1 Parts 1.3 through 1.5 for their area to the applicable Regional
Entity within 75 calendar days of receiving a request for such data, unless otherwise
agreed upon by the parties. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]

M3. Each Planning Coordinator or Balancing Authority, shall have evidence, such as dated
e-mails or dated transmittal letters that it provided the data requested by the
applicable Regional Entity in accordance with Requirement R3.
R4.

Any Applicable Entity shall, in response to a written request for the data included in
parts 1.3-1.5 of Requirement R1 from a Planning Coordinator, Balancing Authority,
Transmission Planner or Resource Planner with a demonstrated need for such data in
order to conduct reliability assessments of the Bulk Electric System, provide or
otherwise make available that data to the requesting entity. This requirement does
not modify an entity’s obligation pursuant to Requirement R2 to respond to data
requests issued by its Planning Coordinator or Balancing Authority pursuant to
Requirement R1. Unless otherwise agreed upon, the Applicable Entity: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
•

shall not be required to alter the format in which it maintains or uses the data;

•

shall provide the requested data within 45 calendar days of the written
request, subject to part 4.1 of this requirement; unless providing the
requested data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements

4.1. If the Applicable Entity does not provide data requested because (1) the
requesting entity did not demonstrate a reliability need for the data; or (2)
providing the data would conflict with the Applicable Entity’s confidentiality,
regulatory, or security requirements, the Applicable Entity shall, within 30
calendar days of the written request, provide a written response to the
requesting entity specifying the data that is not being provided and on what
basis.
M4. Each Applicable Entity identified in Requirement R4 shall have evidence such as dated
e-mails or dated transmittal letters that it provided the data requested or provided a
written response specifying the data that is not being provided and the basis for not
providing the data in accordance with Requirement R4.

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MOD-031-2 3 — Demand and Energy Data

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The Applicable Entity shall keep data or evidence to show compliance with
Requirements R1 through R4, and Measures M1 through M4, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an Applicable Entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None

Page 5 of 11

MOD-031-2 3 — Demand and Energy Data

Table of Compliance Elements
R#

Time Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

N/A

N/A

N/A

The Planning Coordinator
or Balancing Authority
developed and issued a
data request but failed to
include either the entity(s)
necessary to provide the
data or the timetable for
providing the data.

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part
1.3.1 through part
1.3.4

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.3.1 through part
1.3.4

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide one of the
requested items in
Requirement R1 part

The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide two of the
requested items in
Requirement R1 part

The Applicable Entity, as
defined in the data request
developed in Requirement
R1, failed to provide three
or more of the requested
items in Requirement R1
part 1.4.1 through part
1.4.5

R1

Long-term
Planning

Medium

R2

Long-term
Planning

Medium The Applicable Entity,
as defined in the data
request developed in
Requirement R1, failed
to provide all of the
data requested in
Requirement R1 part
1.5.1 through part
1.5.5

High VSL

Severe VSL

OR

Page 6 of 11

MOD-031-2 3 — Demand and Energy Data

did so after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 6 days
after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

R3

Long-term
Planning

Medium The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 75 days

1.4.1 through part
1.4.5

1.4.1 through part
1.4.5

OR

OR

OR

The Applicable Entity,
as defined in the data
request developed in
Requirement R1,
provided the data
requested in
Requirement R1, but
did so 6 days after the
date indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2 but prior to 11
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Applicable Entity, as
defined in the data request
The Applicable Entity, developed in Requirement
R1, failed to provide the
as defined in the data
data requested in the
request developed in
timetable provided
Requirement R1,
pursuant to Requirement
provided the data
R1 prior to 16 days after
requested in
the date indicated in the
Requirement R1, but
timetable provided
did so 11 days after
pursuant to Requirement
the date indicated in
the timetable provided R1 part 1.2.
pursuant to
Requirement R1 part
1.2 but prior to 15
days after the date
indicated in the
timetable provided
pursuant to
Requirement R1 part
1.2.

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 80 days

The Planning
Coordinator or
Balancing Authority, in
response to a request
by the Regional Entity,
made available the
data requested, but
did so after 85 days

The Planning Coordinator
or Balancing Authority, in
response to a request by
the Regional Entity, failed
to make available the data
requested prior to 91 days

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MOD-031-2 3 — Demand and Energy Data

R4

Long-term
Planning

from the date of
request but prior to 81
days from the date of
the request.

from the date of
request but prior to 86
days from the date of
the request.

from the date of
request but prior to 91
days from the date of
the request.

or more from the date of
the request.

Medium The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
45 days from the date
of request but prior to
51 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
50 days from the date
of request but prior to
56 days from the date
of the request

The Applicable Entity
provided or otherwise
made available the
data to the requesting
entity but did so after
55 days from the date
of request but prior to
61 days from the date
of the request

The Applicable Entity failed
to provide or otherwise
make available the data to
the requesting entity
within 60 days from the
date of the request

OR

OR

OR

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 30 days of the
written request but
prior to 36 days of the
written resquest.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 35 days of the
written request but
prior to 41 days of the
written resquest.

The Applicable Entity
that is not providing
the data requested
provided a written
response specifying
the data that is not
being provided and on
what basis but did so
after 40 days of the
written request but
prior to 46 days of the
written resquest.

OR
The Applicable Entity that
is not providing the data
requested failed to provide
a written response
specifying the data that is
not being provided and on
what basis within 45 days
of the written resquest.

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MOD-031-2 3 — Demand and Energy Data

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

Action

1

May 6, 2014

1

February 19,
2015

Adopted by the NERC Board
of Trustees
FERC order approving MOD031-1

2

November 5,
2015

Adopted by the NERC Board
of Trustees

2

February 18,
2016

FERC order approving MOD031-2. Docket No. RD16-1000

3

Change Tracking

Adopted by the NERC Board
of Trustees

Page 9 of 11

MOD-031-3 — Demand and Energy DataApplication Guidelines
Guidelines and Technical Basis
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:
Rationale for R1: To ensure that when Planning Coordinators (PCs) or Balancing Authorities
(BAs) request data (R1), they identify the entities that must provide the data (Applicable Entity
in part 1.1), the data to be provided (parts 1.3 – 1.5) and the due dates (part 1.2) for the
requested data.
For Requirement R1 part 1.3.2.1, if the Demand does not vary due to weather-related
conditions (e.g., temperature, humidity or wind speed), or the weather assumed in the forecast
was the same as the actual weather, the weather normalized actual Demand will be the same
as the actual demand reported for Requirement R1 part 1.3.2. Otherwise the annual peak hour
weather normalized actual Demand will be different from the actual demand reported for
Requirement R1 part 1.3.2.
Balancing Authorities are included here to reflect a practice in the WECC Region where BAs are
the entity that perform this requirement in lieu of the PC.
Rationale for R2:
This requirement will ensure that entities identified in Requirement R1, as responsible for
providing data, provide the data in accordance with the details described in the data request
developed in accordance with Requirement R1. In no event shall the Applicable Entity be
required to provide data under this requirement that is outside the scope of parts 1.3 - 1.5 of
Requirement R1.
Rationale for R3:
This requirement will ensure that the Planning Coordinator or when applicable, the Balancing
Authority, provides the data requested by the Regional Entity.
Rationale for R4:
This requirement will ensure that the Applicable Entity will make the data requested by the
Planning Coordinator or Balancing Authority in Requirement R1 available to other applicable
entities (Planning Coordinator, Balancing Authority, Transmission Planner or Resource Planner)
unless providing the data would conflict with the Applicable Entity’s confidentiality, regulatory,
or security requirements. The sharing of documentation of the supporting methods and
assumptions used to develop forecasts as well as information-sharing activities will improve the
efficiency of planning practices and support the identification of needed system
reinforcements.

Page 10 of 11

MOD-031-3 — Demand and Energy DataApplication Guidelines

The obligation to share data under Requirement R4 does not supersede or otherwise modify
any of the Applicable Entity’s existing confidentiality obligations. For instance, if an entity is
prohibited from providing any of the requested data pursuant to confidentiality provisions of an
Open Access Transmission Tariff or a contractual arrangement, Requirement R4 does not
require the Applicable Entity to provide the data to a requesting entity. Rather, under Part 4.1,
the Applicable Entity must simply provide written notification to the requesting entity that it
will not be providing the data and the basis for not providing the data. If the Applicable Entity is
subject to confidentiality obligations that allow the Applicable Entity to share the data only if
certain conditions are met, the Applicable Entity shall ensure that those conditions are met
within the 45-day time period provided in Requirement R4, communicate with the requesting
entity regarding an extension of the 45-day time period so as to meet all those conditions, or
provide justification under Part 4.1 as to why those conditions cannot be met under the
circumstances.

Page 11 of 11

MOD-033-2 — Steady-State and Dynamic System Model Validation

A. Introduction
1.

Title: Steady-State and Dynamic System Model Validation

2.

Number:

3.

Purpose:
To establish consistent validation requirements to facilitate the
collection of accurate data and building of planning models to analyze the reliability of
the interconnected transmission system.

4.

Applicability:

MOD-033-2

4.1. Functional Entities:
4.1.1 Planning Coordinator
4.1.2 Reliability Coordinator
4.1.3 Transmission Operator
5.

Effective Date: See Implementation Plan.

Draft 2 of MOD-033-2
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Page 1 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

B. Requirements and Measures
R1.

Each Planning Coordinator shall implement a documented data validation process
that includes the following attributes: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
1.1. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning power flow model to actual system behavior,
represented by a state estimator case or other Real-time data sources, at least
once every 24 calendar months through simulation;
1.2. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning dynamic model to actual system response, through
simulation of a dynamic local event, at least once every 24 calendar months (use
a dynamic local event that occurs within 24 calendar months of the last dynamic
local event used in comparison, and complete each comparison within 24
calendar months of the dynamic local event). If no dynamic local event occurs
within the 24 calendar months, use the next dynamic local event that occurs;
1.3. Guidelines the Planning Coordinator will use to determine unacceptable
differences in performance under Part 1.1 or 1.2; and
1.4. Guidelines to resolve the unacceptable differences in performance identified
under Part 1.3.

M1. Each Planning Coordinator shall provide evidence that it has a documented validation

process according to Requirement R1 as well as evidence that demonstrates the
implementation of the required components of the process.

R2.

Each Reliability Coordinator and Transmission Operator shall provide actual system
behavior data (or a written response that it does not have the requested data) to any
Planning Coordinator performing validation under Requirement R1 within 30 calendar
days of a written request, such as, but not limited to, state estimator case or other
Real-time data (including disturbance data recordings) necessary for actual system
response validation. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

M2. Each Reliability Coordinator and Transmission Operator shall provide evidence, such

as email notices or postal receipts showing recipient and date that it has distributed
the requested data or written response that it does not have the data, to any Planning
Coordinator performing validation under Requirement R1 within 30 days of a written
request in accordance with Requirement R2; or a statement by the Reliability
Coordinator or Transmission Operator that it has not received notification regarding
data necessary for validation by any Planning Coordinator.

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Page 2 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity in their
respective roles of monitoring and enforcing compliance with the NERC
Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance with
Requirements R1 through R2, and Measures M1 through M2, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an applicable entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Refer to Section 3.0 of Appendix 4C of the NERC Rules of Procedure for a list of
compliance monitoring and assessment processes.
1.4. Additional Compliance Information
None

Draft 2 of MOD-033-2
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Page 3 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

Table of Compliance Elements
R#

Time Horizon

Violation Severity Levels

VRF
Lower VSL

R1

Long-term
Planning

Medium The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address one of the
four required topics
under Requirement
R1;

High VSL

Severe VSL

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address two of the
four required topics
under Requirement
R1;

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address three of the
four required topics
under Requirement
R1;

The Planning
Coordinator did not
have a validation
process at all or did
not document or
implement any of the
four required topics
under Requirement
R1;

OR

OR

OR

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation within 28
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months;

The Planning
Coordinator did not
validate its portion of
the system in the
power flow model as
required by part 1.1
within 36 calendar
months;

OR

OR

OR
The Planning
Coordinator did not
perform simulation as
Draft 2 of MOD-033-2
January 2020

Moderate VSL

Page 4 of 10

OR

OR
The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 36 calendar

MOD-033-2 — Steady-State and Dynamic System Model Validation

R#

R2

Time Horizon

Long-term
Planning

Draft 2 of MOD-033-2
January 2020

Violation Severity Levels

VRF

Lower

Lower VSL

Moderate VSL

High VSL

Severe VSL

required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation within 28
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months.

months (or the next
dynamic local event in
cases where there is
more than 24 months
between events).

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning

Page 5 of 10

MOD-033-2 — Steady-State and Dynamic System Model Validation

R#

Time Horizon

Violation Severity Levels

VRF
Lower VSL

Moderate VSL

High VSL

Severe VSL

Coordinator within 30
calendar days of the
written request, but
did provide the data
(or written response
that it does not have
the requested data) in
less than or equal to
45 calendar days.

Coordinator within 30
calendar days of the
written request, but
did provide the data
(or written response
that it does not have
the requested data) in
greater than 45
calendar days but less
than or equal to 60
calendar days.

Coordinator within 30
calendar days of the
written request, but
did provide the data
(or written response
that it does not have
the requested data) in
greater than 60
calendar days but less
than or equal to 75
calendar days.

Coordinator within 75
calendar days;

D. Regional Variances
None.

E. Interpretations
None.

F. Associated Documents
None.

Draft 2 of MOD-033-2
January 2020

Page 6 of 10

OR
The Reliability
Coordinator or
Transmission Operator
provided a written
response that it does
not have the
requested data, but
actually had the data.

MOD-033-2 — Steady-State and Dynamic System Model Validation

Guidelines and Technical Basis
Requirement R1:
The requirement focuses on the results-based outcome of developing a process for and
performing a validation, but does not prescribe a specific method or procedure for the
validation outside of the attributes specified in the requirement. For further information on
suggested validation procedures, see “Procedures for Validation of Powerflow and Dynamics
Cases” produced by the NERC Model Working Group.
The specific process is left to the judgment of the Planning Coordinator, but the Planning
Coordinator is required to develop and include in its process guidelines for evaluating
discrepancies between actual system behavior or response and expected system performance
for determining whether the discrepancies are unacceptable.
For the validation in part 1.1, the state estimator case or other Real-time data should be taken
as close to system peak as possible. However, other snapshots of the system could be used if
deemed to be more appropriate by the Planning Coordinator. While the requirement specifies
“once every 24 calendar months,” entities are encouraged to perform the comparison on a
more frequent basis.
In performing the comparison required in part 1.1, the Planning Coordinator may consider,
among other criteria:
1. System load;
2. Transmission topology and parameters;
3. Voltage at major buses; and
4. Flows on major transmission elements.
The validation in part 1.1 would include consideration of the load distribution and load power
factors (as applicable) used in the power flow models. The validation may be made using
metered load data if state estimator cases are not available. The comparison of system load
distribution and load power factors shall be made on an aggregate company or power flow
zone level at a minimum but may also be made on a bus by bus, load pocket (e.g., within a
Balancing Authority), or smaller area basis as deemed appropriate by the Planning Coordinator.
The scope of dynamics model validation is intended to be limited, for purposes of part 1.2, to
the Planning Coordinator’s planning area, and the intended emphasis under the requirement is
on local events or local phenomena, not the whole Interconnection.
The validation required in part 1.2 may include simulations that are to be compared with actual
system data and may include comparisons of:
•

Voltage oscillations at major buses

•

System frequency (for events with frequency excursions)

•

Real and reactive power oscillations on generating units and major inter-area ties

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MOD-033-2 — Steady-State and Dynamic System Model Validation

Determining when a dynamic local event might occur may be unpredictable, and because of the
analytic complexities involved in simulation, the time parameters in part 1.2 specify that the
comparison period of “at least once every 24 calendar months” is intended to both provide for
at least 24 months between dynamic local events used in the comparisons and that
comparisons must be completed within 24 months of the date of the dynamic local event used.
This clarification ensures that PCs will not face a timing scenario that makes it impossible to
comply. If the time referred to the completion time of the comparison, it would be possible for
an event to occur in month 23 since the last comparison, leaving only one month to complete
the comparison. With the 30 day timeframe in Requirement R2 for TOPs or RCs to provide
actual system behavior data (if necessary in the comparison), it would potentially be impossible
to complete the comparison within the 24 month timeframe.
In contrast, the requirement language clarifies that the time frame between dynamic local
events used in the comparisons should be within 24 months of each other (or, as specified at
the end of part 1.2, in the event more than 24 months passes before the next dynamic local
event, the comparison should use the next dynamic local event that occurs). Each comparison
must be completed within 24 months of the dynamic local event used. In this manner, the
potential problem with a “month 23” dynamic local event described above is resolved. For
example, if a PC uses for comparison a dynamic local event occurring on day 1 of month 1, the
PC has 24 calendar months from that dynamic local event’s occurrence to complete the
comparison. If the next dynamic event the PC chooses for comparison occurs in month 23, the
PC has 24 months from that dynamic local event’s occurrence to complete the comparison.
Part 1.3 requires the PC to include guidelines in its documented validation process for
determining when discrepancies in the comparison of simulation results with actual system
results are unacceptable. The PC may develop the guidelines required by parts 1.3 and 1.4
itself, reference other established guidelines, or both. For the power flow comparison, as an
example, this could include a guideline the Planning Coordinator will use that flows on 500 kV
lines should be within 10% or 100 MW, whichever is larger. It could be different percentages or
MW amounts for different voltage levels. Or, as another example, the guideline for voltage
comparisons could be that it must be within 1%. But the guidelines the PC includes within its
documented validation process should be meaningful for the Planning Coordinator’s system.
Guidelines for the dynamic event comparison may be less precise. Regardless, the comparison
should indicate that the conclusions drawn from the two results should be consistent. For
example, the guideline could state that the simulation result will be plotted on the same graph
as the actual system response. Then the two plots could be given a visual inspection to see if
they look similar or not. Or a guideline could be defined such that the rise time of the transient
response in the simulation should be within 20% of the rise time of the actual system response.
As for the power flow guidelines, the dynamic comparison criteria should be meaningful for the
Planning Coordinator’s system.
The guidelines the PC includes in its documented validation process to resolve differences in
Part 1.4 could include direct coordination with the data owner, and, if necessary, through the
provisions of MOD-032-1, Requirement R3 (i.e., the validation performed under this
requirement could identify technical concerns with the data). In other words, while this
standard is focused on validation, results of the validation may identify data provided under the
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MOD-033-2 — Steady-State and Dynamic System Model Validation

modeling data standard that needs to be corrected. If a model with estimated data or a generic
model is used for a generator, and the model response does not match the actual response,
then the estimated data should be corrected or a more detailed model should be requested
from the data provider.
While the validation is focused on the Planning Coordinator’s planning area, the model for the
validation should be one that contains a wider area of the Interconnection than the Planning
Coordinator’s area. If the simulations can be made to match the actual system responses by
reasonable changes to the data in the Planning Coordinator’s area, then the Planning
Coordinator should make those changes in coordination with the data provider. However, for
some disturbances, the data in the Planning Coordinator’s area may not be what is causing the
simulations to not match actual responses. These situations should be reported to the Electric
Reliability Organization (ERO). The guidelines the Planning Coordinator includes under Part 1.4
could cover these situations.
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:
In FERC Order No. 693, paragraph 1210, the Commission directed inclusion of “a requirement
that the models be validated against actual system responses.” Furthermore, the Commission
directs in paragraph 1211, “that actual system events be simulated and if the model output is
not within the accuracy required, the model shall be modified to achieve the necessary
accuracy.” Paragraph 1220 similarly directs validation against actual system responses relative
to dynamics system models. In FERC Order 890, paragraph 290, the Commission states that
“the models should be updated and benchmarked to actual events.” Requirement R1 addresses
these directives.
Requirement R1 requires the Planning Coordinator to implement a documented data validation
process to validate data in the Planning Coordinator’s portion of the existing system in the
steady-state and dynamic models to compare performance against expected behavior or
response, which is consistent with the Commission directives. The validation of the full
Interconnection-wide cases is left up to the Electric Reliability Organization (ERO) or its
designees, and is not addressed by this standard. The following items were chosen for the
validation requirement:
A. Comparison of performance of the existing system in a planning power flow model to actual
system behavior; and
B. Comparison of the performance of the existing system in a planning dynamics model to
actual system response.
Implementation of these validations will result in more accurate power flow and dynamic
models. This, in turn, should result in better correlation between system flows and voltages
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MOD-033-2 — Steady-State and Dynamic System Model Validation

seen in power flow studies and the actual values seen by system operators during outage
conditions. Similar improvements should be expected for dynamics studies, such that the
results will more closely match the actual responses of the power system to disturbances.
Validation of model data is a good utility practice, but it does not easily lend itself to Reliability
Standards requirement language. Furthermore, it is challenging to determine specifications for
thresholds of disturbances that should be validated and how they are determined. Therefore,
this requirement focuses on the Planning Coordinator performing validation pursuant to its
process, which must include the attributes listed in parts 1.1 through 1.4, without specifying the
details of “how” it must validate, which is necessarily dependent upon facts and circumstances.
Other validations are best left to guidance rather than standard requirements.
Rationale for R2:
The Planning Coordinator will need actual system behavior data in order to perform the
validations required in R1. The Reliability Coordinator or Transmission Operator may have this
data. Requirement R2 requires the Reliability Coordinator and Transmission Operator to supply
actual system data, if it has the data, to any requesting Planning Coordinator for purposes of
model validation under Requirement R1.
This could also include information the Reliability Coordinator or Transmission Operator has at
a field site. For example, if a PMU or DFR is at a generator site and it is recording the
disturbance, the Reliability Coordinator or Transmission Operator would typically have that
data.

Version History
Version

Date

Action

1

February 6,
2014

Adopted by the NERC Board of
Trustees.

1

May 1, 2014

FERC Order issued approving
MOD-033-1.

2

Draft 2 of MOD-033-2
January 2020

Change Tracking

Developed as a new
standard for system
validation to address
outstanding directives
from FERC Order No. 693
and recommendations
from several other
sources.

Adopted by the NERC Board of
Trustees.

Page 10 of 10

MOD‐033‐2 — Steady‐State and Dynamic System Model Validation 

A. Introduction
1.

Title:  Steady‐State and Dynamic System Model Validation 

2.

Number: 

3.

Purpose:   To establish consistent validation requirements to facilitate the 
collection of accurate data and building of planning models to analyze the reliability of 
the interconnected transmission system. 

4.

Applicability: 

MOD‐033‐2 

4.1. Functional Entities: 
4.1.1 Planning Coordinator 
4.1.2 Reliability Coordinator 
4.1.3 Transmission Operator 
5.

Effective Date:  See Implementation Plan. 

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MOD‐033‐2 — Steady‐State and Dynamic System Model Validation 

B. Requirements and Measures
R1.

Each Planning Coordinator shall implement a documented data validation process  
that includes the following attributes: [Violation Risk Factor: Medium] [Time Horizon: 
Long‐term Planning] 
1.1. Comparison of the performance of the Planning Coordinator’s portion of the 
existing system in a planning power flow model to actual system behavior, 
represented by a state estimator case or other Real‐time data sources, at least 
once every 24 calendar months through simulation;  
1.2. Comparison of the performance of the Planning Coordinator’s portion of the 
existing system in a planning dynamic model to actual system response, through 
simulation of a dynamic local event, at least once every 24 calendar months (use 
a dynamic local event that occurs within 24 calendar months of the last dynamic 
local event used in comparison, and complete each comparison within 24 
calendar months of the dynamic local event).  If no dynamic local event occurs 
within the 24 calendar months, use the next dynamic local event that occurs;  
1.3. Guidelines the Planning Coordinator will use to determine unacceptable 
differences in performance under Part 1.1 or 1.2; and  
1.4. Guidelines to resolve the unacceptable differences in performance identified 
under Part 1.3. 

M1. Each Planning Coordinator shall provide evidence that it has a documented validation 

process according to Requirement R1 as well as evidence that demonstrates the 
implementation of the required components of the process. 
R2.

Each Reliability Coordinator and Transmission Operator shall provide actual system 
behavior data (or a written response that it does not have the requested data) to any 
Planning Coordinator performing validation under Requirement R1 within 30 calendar 
days of a written request, such as, but not limited to, state estimator case or other 
Real‐time data (including disturbance data recordings) necessary for actual system 
response validation. [Violation Risk Factor: Lower] [Time Horizon: Long‐term Planning] 

M2. Each Reliability Coordinator and Transmission Operator shall provide evidence, such 

as email notices or postal receipts showing recipient and date that it has distributed 
the requested data or written response that it does not have the data, to any Planning 
Coordinator performing validation under Requirement R1 within 30 days of a written 
request in accordance with Requirement R2; or a statement by the Reliability 
Coordinator or Transmission Operator that it has not received notification regarding 
data necessary for validation by any Planning Coordinator. 

Draft 1 2 of MOD‐033‐2 
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MOD‐033‐2 — Steady‐State and Dynamic System Model Validation 

C. Compliance
1.

Compliance Monitoring Process 
1.1. Compliance Enforcement Authority 
“Compliance Enforcement Authority” means NERC or the Regional Entity in their 
respective roles of monitoring and enforcing compliance with the NERC 
Reliability Standards. 
1.2. Evidence Retention  
The following evidence retention periods identify the period of time an entity is 
required to retain specific evidence to demonstrate compliance. For instances 
where the evidence retention period specified below is shorter than the time 
since the last audit, the Compliance Enforcement Authority may ask an entity to 
provide other evidence to show that it was compliant for the full time period 
since the last audit. 
The applicable entity shall keep data or evidence to show compliance with 
Requirements R1 through R2, and Measures M1 through M2, since the last audit, 
unless directed by its Compliance Enforcement Authority to retain specific 
evidence for a longer period of time as part of an investigation. 
If an applicable entity is found non‐compliant, it shall keep information related 
to the non‐compliance until mitigation is complete and approved, or for the time 
specified above, whichever is longer. 
The Compliance Enforcement Authority shall keep the last audit records and all 
requested and submitted subsequent audit records.  
1.3. Compliance Monitoring and Assessment Processes: 
Refer to Section 3.0 of Appendix 4C of the NERC Rules of Procedure for a list of 
compliance monitoring and assessment processes. 
1.4. Additional Compliance Information 
None 

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October January 20192020

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MOD‐033‐2 — Steady‐State and Dynamic System Model Validation 

Table of Compliance Elements
R # 

Time Horizon 

Violation Severity Levels 

VRF 
Lower VSL 

R1 

Long‐term 
Planning 

High VSL 

Severe VSL 

The Planning 
Coordinator 
documented and 
implemented a 
process to validate 
data but did not 
address two of the 
four required topics 
under Requirement 
R1;  

The Planning 
Coordinator 
documented and 
implemented a 
process to validate 
data but did not 
address three of the 
four required topics 
under Requirement 
R1; 

The Planning 
Coordinator did not 
have a validation 
process at all or did 
not document or 
implement any of the 
four required topics 
under Requirement 
R1; 

OR 

OR 

OR 

The Planning 
Coordinator did not 
perform simulation as 
required by part 1.1 
within 24 calendar 
months but did 
perform the 
simulation within 28 
calendar months; 

The Planning 
Coordinator did not 
perform simulation as 
required by part 1.1 
within 24 calendar 
months but did 
perform the 
simulation in greater 
than 28 calendar 
months but less than 
or equal to 32 
calendar months; 

The Planning 
Coordinator did not 
perform simulation as 
required by part 1.1 
within 24 calendar 
months but did 
perform the 
simulation in greater 
than 32 calendar 
months but less than 
or equal to 36 
calendar months; 

The Planning 
Coordinator did not 
validate its portion of 
the system in the 
power flow model as 
required by part 1.1 
within 36 calendar 
months; 

OR 

OR 

Medium  The Planning 
Coordinator 
documented and 
implemented a 
process to validate 
data but did not 
address one of the 
four required topics 
under Requirement 
R1;  

OR 
The Planning 
Coordinator did not 
perform simulation as 
Draft 1 2 of MOD‐033‐2 
October January 20192020

Moderate VSL 

Page 4 of 10

OR 

OR 
The Planning 
Coordinator did not 
perform simulation as 
required by part 1.2 
within 36 calendar 

MOD‐033‐2 — Steady‐State and Dynamic System Model Validation 

R # 

Time Horizon 

Violation Severity Levels 

VRF 
Lower VSL 

Moderate VSL 

High VSL 

Severe VSL 

required by part 1.2 
within 24 calendar 
months (or the next 
dynamic local event in 
cases where there is 
more than 24 months 
between events) but 
did perform the 
simulation within 28 
calendar months. 

The Planning 
Coordinator did not 
perform simulation as 
required by part 1.2 
within 24 calendar 
months (or the next 
dynamic local event in 
cases where there is 
more than 24 months 
between events) but 
did perform the 
simulation in greater 
than 28 calendar 
months but less than 
or equal to 32 
calendar months. 

The Planning 
Coordinator did not 
perform simulation as 
required by part 1.2 
within 24 calendar 
months (or the next 
dynamic local event in 
cases where there is 
more than 24 months 
between events) but 
did perform the 
simulation in greater 
than 32 calendar 
months but less than 
or equal to 36 
calendar months. 

months (or the next 
dynamic local event in 
cases where there is 
more than 24 months 
between events). 

The Reliability 
Coordinator or 
Transmission Operator 
did not provide 
requested actual 
system behavior data 
(or a written response 
that it does not have 
the requested data) to 
a requesting Planning 

The Reliability 
Coordinator or 
Transmission Operator 
did not provide 
requested actual 
system behavior data 
(or a written response 
that it does not have 
the requested data) to 
a requesting Planning 

R2 

Long‐term 
Planning 

Draft 1 2 of MOD‐033‐2 
October January 20192020

Lower 

The Reliability 
Coordinator or 
Transmission Operator 
did not provide 
requested actual 
system behavior data 
(or a written response 
that it does not have 
the requested data) to 
a requesting Planning 

The Reliability 
Coordinator or 
Transmission Operator 
did not provide 
requested actual 
system behavior data 
(or a written response 
that it does not have 
the requested data) to 
a requesting Planning 

Page 5 of 10

MOD‐033‐2 — Steady‐State and Dynamic System Model Validation 

R # 

Time Horizon 

Violation Severity Levels 

VRF 
Lower VSL 

Moderate VSL 

High VSL 

Severe VSL 

Coordinator within 30 
calendar days of the 
written request, but 
did provide the data 
(or written response 
that it does not have 
the requested data) in 
less than or equal to 
45 calendar days. 

Coordinator within 30 
calendar days of the 
written request, but 
did provide the data 
(or written response 
that it does not have 
the requested data) in 
greater than 45 
calendar days but less 
than or equal to 60 
calendar days. 

Coordinator within 30 
calendar days of the 
written request, but 
did provide the data 
(or written response 
that it does not have 
the requested data) in 
greater than 60 
calendar days but less 
than or equal to 75 
calendar days. 

Coordinator within 75 
calendar days; 
OR 
The Reliability 
Coordinator or 
Transmission Operator 
provided a written 
response that it does 
not have the 
requested data, but 
actually had the data. 

D. Regional Variances
None. 

E. Interpretations
None. 

F. Associated Documents
None. 

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MOD‐033‐2 — Steady‐State and Dynamic System Model Validation Application Guidelines 

Guidelines and Technical Basis 
Requirement R1:  
The requirement focuses on the results‐based outcome of developing a process for and 
performing a validation, but does not prescribe a specific method or procedure for the 
validation outside of the attributes specified in the requirement. For further information on 
suggested validation procedures, see “Procedures for Validation of Powerflow and Dynamics 
Cases” produced by the NERC Model Working Group. 
The specific process is left to the judgment of the Planning Coordinator, but the Planning 
Coordinator is required to develop and include in its process guidelines for evaluating 
discrepancies between actual system behavior or response and expected system performance 
for determining whether the discrepancies are unacceptable.  
For the validation in part 1.1, the state estimator case or other Real‐time data should be taken 
as close to system peak as possible. However, other snapshots of the system could be used if 
deemed to be more appropriate by the Planning Coordinator.  While the requirement specifies 
“once every 24 calendar months,” entities are encouraged to perform the comparison on a 
more frequent basis.   
In performing the comparison required in part 1.1, the Planning Coordinator may consider, 
among other criteria: 
1. System load; 
2. Transmission topology and parameters; 
3. Voltage at major buses; and  
4. Flows on major transmission elements. 
The validation in part 1.1 would include consideration of the load distribution and load power 
factors (as applicable) used in the power flow models.  The validation may be made using 
metered load data if state estimator cases are not available. The comparison of system load 
distribution and load power factors shall be made on an aggregate company or power flow 
zone level at a minimum but may also be made on a bus by bus, load pocket (e.g., within a 
Balancing Authority), or smaller area basis as deemed appropriate by the Planning Coordinator. 
The scope of dynamics model validation is intended to be limited, for purposes of part 1.2, to 
the Planning Coordinator’s planning area, and the intended emphasis under the requirement is 
on local events or local phenomena, not the whole Interconnection. 
The validation required in part 1.2 may include simulations that are to be compared with actual 
system data and may include comparisons of: 


Voltage oscillations at major buses 



System frequency (for events with frequency excursions) 



Real and reactive power oscillations on generating units and major inter‐area ties 

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MOD‐033‐2 — Steady‐State and Dynamic System Model Validation Application Guidelines 

Determining when a dynamic local event might occur may be unpredictable, and because of the 
analytic complexities involved in simulation, the time parameters in part 1.2 specify that the 
comparison period of “at least once every 24 calendar months” is intended to both provide for 
at least 24 months between dynamic local events used in the comparisons and that 
comparisons must be completed within 24 months of the date of the dynamic local event used.  
This clarification ensures that PCs will not face a timing scenario that makes it impossible to 
comply.  If the time referred to the completion time of the comparison, it would be possible for 
an event to occur in month 23 since the last comparison, leaving only one month to complete 
the comparison.  With the 30 day timeframe in Requirement R2 for TOPs or RCs to provide 
actual system behavior data (if necessary in the comparison), it would potentially be impossible 
to complete the comparison within the 24 month timeframe.   
In contrast, the requirement language clarifies that the time frame between dynamic local 
events used in the comparisons should be within 24 months of each other (or, as specified at 
the end of part 1.2, in the event more than 24 months passes before the next dynamic local 
event, the comparison should use the next dynamic local event that occurs).  Each comparison 
must be completed within 24 months of the dynamic local event used.  In this manner, the 
potential problem with a “month 23” dynamic local event described above is resolved.  For 
example, if a PC uses for comparison a dynamic local event occurring on day 1 of month 1, the 
PC has 24 calendar months from that dynamic local event’s occurrence to complete the 
comparison.  If the next dynamic event the PC chooses for comparison occurs in month 23, the 
PC has 24 months from that dynamic local event’s occurrence to complete the comparison.   
Part 1.3 requires the PC to include guidelines in its documented validation process for 
determining when discrepancies in the comparison of simulation results with actual system 
results are unacceptable.  The PC may develop the guidelines required by parts 1.3 and 1.4 
itself, reference other established guidelines, or both.  For the power flow comparison, as an 
example, this could include a guideline the Planning Coordinator will use that flows on 500 kV 
lines should be within 10% or 100 MW, whichever is larger. It could be different percentages or 
MW amounts for different voltage levels. Or, as another example, the guideline for voltage 
comparisons could be that it must be within 1%.  But the guidelines the PC includes within its 
documented validation process should be meaningful for the Planning Coordinator’s system. 
Guidelines for the dynamic event comparison may be less precise.  Regardless, the comparison 
should indicate that the conclusions drawn from the two results should be consistent.  For 
example, the guideline could state that the simulation result will be plotted on the same graph 
as the actual system response. Then the two plots could be given a visual inspection to see if 
they look similar or not. Or a guideline could be defined such that the rise time of the transient 
response in the simulation should be within 20% of the rise time of the actual system response.  
As for the power flow guidelines, the dynamic comparison criteria should be meaningful for the 
Planning Coordinator’s system. 
The guidelines the PC includes in its documented validation process to resolve differences in 
Part 1.4 could include direct coordination with the data owner, and, if necessary, through the 
provisions of MOD‐032‐1, Requirement R3 (i.e., the validation performed under this 
requirement could identify technical concerns with the data).   In other words, while this 
standard is focused on validation, results of the validation may identify data provided under the 
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MOD‐033‐2 — Steady‐State and Dynamic System Model Validation Application Guidelines 

modeling data standard that needs to be corrected. If a model with estimated data or a generic 
model is used for a generator, and the model response does not match the actual response, 
then the estimated data should be corrected or a more detailed model should be requested 
from the data provider. 
While the validation is focused on the Planning Coordinator’s planning area, the model for the 
validation should be one that contains a wider area of the Interconnection than the Planning 
Coordinator’s area. If the simulations can be made to match the actual system responses by 
reasonable changes to the data in the Planning Coordinator’s area, then the Planning 
Coordinator should make those changes in coordination with the data provider. However, for 
some disturbances, the data in the Planning Coordinator’s area may not be what is causing the 
simulations to not match actual responses. These situations should be reported to the Electric 
Reliability Organization (ERO). The guidelines the Planning Coordinator includes under Part 1.4 
could cover these situations. 

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:  
In FERC Order No. 693, paragraph 1210, the Commission directed inclusion of “a requirement 
that the models be validated against actual system responses.”  Furthermore, the Commission 
directs in paragraph 1211, “that actual system events be simulated and if the model output is 
not within the accuracy required, the model shall be modified to achieve the necessary 
accuracy.”  Paragraph 1220 similarly directs validation against actual system responses relative 
to dynamics system models. In FERC Order 890, paragraph 290, the Commission states that 
“the models should be updated and benchmarked to actual events.” Requirement R1 addresses 
these directives.     
Requirement R1 requires the Planning Coordinator to implement a documented data validation 
process to validate data in the Planning Coordinator’s portion of the existing system in the 
steady‐state and dynamic models to compare performance against expected behavior or 
response, which is consistent with the Commission directives.  The validation of the full 
Interconnection‐wide cases is left up to the Electric Reliability Organization (ERO) or its 
designees, and is not addressed by this standard. The following items were chosen for the 
validation requirement: 
A. Comparison of performance of the existing system in a planning power flow model to actual 
system behavior; and 
B. Comparison of the performance of the existing system in a planning dynamics model to 
actual system response. 
Implementation of these validations will result in more accurate power flow and dynamic 
models. This, in turn, should result in better correlation between system flows and voltages 
Draft 1 2 of MOD‐033‐2 
October January 20192020

Page 9 of 10

MOD‐033‐2 — Steady‐State and Dynamic System Model Validation Application Guidelines 

seen in power flow studies and the actual values seen by system operators during outage 
conditions. Similar improvements should be expected for dynamics studies, such that the 
results will more closely match the actual responses of the power system to disturbances. 
Validation of model data is a good utility practice, but it does not easily lend itself to Reliability 
Standards requirement language.  Furthermore, it is challenging to determine specifications for 
thresholds of disturbances that should be validated and how they are determined.  Therefore, 
this requirement focuses on the Planning Coordinator performing validation pursuant to its 
process, which must include the attributes listed in parts 1.1 through 1.4, without specifying the 
details of “how” it must validate, which is necessarily dependent upon facts and circumstances. 
Other validations are best left to guidance rather than standard requirements.   

Rationale for R2:   
The Planning Coordinator will need actual system behavior data in order to perform the 
validations required in R1. The Reliability Coordinator or Transmission Operator may have this 
data. Requirement R2 requires the Reliability Coordinator and Transmission Operator to supply 
actual system data, if it has the data, to any requesting Planning Coordinator for purposes of 
model validation under Requirement R1. 
This could also include information the Reliability Coordinator or Transmission Operator has at 
a field site.  For example, if a PMU or DFR is at a generator site and it is recording the 
disturbance, the Reliability Coordinator or Transmission Operator would typically have that 
data. 

Version History

Version 

Date 

Action  

Change Tracking  

1 

February 6, 
2014 

Adopted by the NERC Board of  Developed as a new 
Trustees. 
standard for system 
validation to address 
outstanding directives 
from FERC Order No. 693 
and recommendations 
from several other 
sources. 

1 

May 1, 2014 

FERC Order issued approving 
MOD‐033‐1.  

2 

Adopted by the NERC Board of   
Trustees. 

Draft 1 2 of MOD‐033‐2 
October January 20192020

Page 10 of 10

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

A. Introduction
1.

Title: Steady-State and Dynamic System Model Validation

2.

Number:

3.

Purpose:
To establish consistent validation requirements to facilitate the
collection of accurate data and building of planning models to analyze the reliability of
the interconnected transmission system.

4.

Applicability:

MOD-033-21

4.1. Functional Entities:
4.1.1 Planning Authority and Planning Coordinator (hereafter referred to as
“Planning Coordinator”)
4.1.24.1.1
This proposed standard combines “Planning Authority” with
“Planning Coordinator” in the list of applicable functional entities. The
NERC Functional Model lists “Planning Coordinator” while the
registration criteria list “Planning Authority,” and they are not yet
synchronized. Until that occurs, the proposed standard applies to both
Planning Authority and Planning Coordinator.

5.

4.1.34.1.2

Reliability Coordinator

4.1.44.1.3

Transmission Operator

Effective Date:
MOD-033-1 shall become effective on the first day of the first calendar quarter that is
36 months 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 that is 36
months after the date the standard is adopted by the NERC Board of Trustees or as
otherwise provided for in that jurisdiction.See Implementation Plan.

6.

Background:
MOD-033-1 exists in conjunction with MOD-032-1, both of which are related to
system-level modeling and validation. Reliability Standard MOD-032-1 is a
consolidation and replacement of existing MOD-010-0, MOD-011-0, MOD-012-0,
MOD-013-1, MOD-014-0, and MOD-015-0.1, and it requires data submission by
applicable data owners to their respective Transmission Planners and Planning
Coordinators to support the Interconnection-wide case building process in their
Interconnection. Reliability Standard MOD-033-1 is a new standard, and it requires
each Planning Coordinator to implement a documented process to perform model
validation within its planning area.

Page 1 of 12

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

The transition and focus of responsibility upon the Planning Coordinator function in
both standards are driven by several recommendations and FERC directives (to
include several remaining directives from FERC Order No. 693), which are discussed in
greater detail in the rationale sections of the standards. One of the most recent and
significant set of recommendations came from the NERC Planning Committee’s
System Analysis and Modeling Subcommittee (SAMS). SAMS proposed several
improvements to the modeling data standards, to include consolidation of the
standards (that whitepaper is available from the December 2012 NERC Planning
Committee’s agenda package, item 3.4, beginning on page 99, here:
http://www.nerc.com/comm/PC/Agendas%20Highlights%20and%20Minutes%20DL/2
012/2012_Dec_PC%20Agenda.pdf).
The focus of validation in this standard is not Interconnection-wide phenomena, but
on the Planning Coordinator’s portion of the existing system. The Reliability Standard
requires Planning Coordinators to implement a documented data validation process
for power flow and dynamics. For the dynamics validation, the target of validation is
those events that the Planning Coordinator determines are dynamic local events. A
dynamic local event could include such things as closing a transmission line near a
generating plant. A dynamic local event is a disturbance on the power system that
produces some measurable transient response, such as oscillations. It could involve
one small area of the system or a generating plant oscillating against the rest of the
grid. The rest of the grid should not have a significant effect. Oscillations involving
large areas of the grid are not local events. However, a dynamic local event could also
be a subset of a larger disturbance involving large areas of the grid.
B. Requirements and Measures
R1.

Each Planning Coordinator shall implement a documented data validation process
that includes the following attributes: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
1.1. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning power flow model to actual system behavior,
represented by a state estimator case or other Real-time data sources, at least
once every 24 calendar months through simulation;
1.2. Comparison of the performance of the Planning Coordinator’s portion of the
existing system in a planning dynamic model to actual system response, through
simulation of a dynamic local event, at least once every 24 calendar months (use
a dynamic local event that occurs within 24 calendar months of the last dynamic
local event used in comparison, and complete each comparison within 24
calendar months of the dynamic local event). If no dynamic local event occurs
within the 24 calendar months, use the next dynamic local event that occurs;
1.3. Guidelines the Planning Coordinator will use to determine unacceptable
differences in performance under Part 1.1 or 1.2; and

Page 2 of 12

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

1.4. Guidelines to resolve the unacceptable differences in performance identified
under Part 1.3.
M1. Each Planning Coordinator shall provide evidence that it has a documented validation

process according to Requirement R1 as well as evidence that demonstrates the
implementation of the required components of the process.

R2.

Each Reliability Coordinator and Transmission Operator shall provide actual system
behavior data (or a written response that it does not have the requested data) to any
Planning Coordinator performing validation under Requirement R1 within 30 calendar
days of a written request, such as, but not limited to, state estimator case or other
Real-time data (including disturbance data recordings) necessary for actual system
response validation. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

M2. Each Reliability Coordinator and Transmission Operator shall provide evidence, such

as email notices or postal receipts showing recipient and date that it has distributed
the requested data or written response that it does not have the data, to any Planning
Coordinator performing validation under Requirement R1 within 30 days of a written
request in accordance with Requirement R2; or a statement by the Reliability
Coordinator or Transmission Operator that it has not received notification regarding
data necessary for validation by any Planning Coordinator.

Page 3 of 12

MOD-033-1 2 — Steady-State and Dynamic System Model Validation

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity in their
respective roles of monitoring and enforcing compliance with the NERC
Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance with
Requirements R1 through R2, and Measures M1 through M2, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an applicable entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Refer to Section 3.0 of Appendix 4C of the NERC Rules of Procedure for a list of
compliance monitoring and assessment processes.
1.4. Additional Compliance Information
None

Page 4 of 12

MOD-033-2 — Steady-State and Dynamic System Model Validation

Table of Compliance Elements
R#

Time Horizon

Violation Severity Levels

VRF
Lower VSL

R1

Long-term
Planning

Medium The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address one of the
four required topics
under Requirement
R1;

Moderate VSL

High VSL

Severe VSL

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address two of the
four required topics
under Requirement
R1;

The Planning
Coordinator
documented and
implemented a
process to validate
data but did not
address three of the
four required topics
under Requirement
R1;

The Planning
Coordinator did not
have a validation
process at all or did
not document or
implement any of the
four required topics
under Requirement
R1;

OR

OR

OR

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation within 28
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months;

The Planning
Coordinator did not
perform simulation as
required by part 1.1
within 24 calendar
months but did
perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months;

The Planning
Coordinator did not
validate its portion of
the system in the
power flow model as
required by part 1.1
within 36 calendar
months;

OR

OR

OR
The Planning
Coordinator did not
perform simulation as

Page 5 of 12

OR

OR
The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 36 calendar

MOD-033-2 — Steady-State and Dynamic System Model Validation

R2

Long-term
Planning

Lower

required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation within 28
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 28 calendar
months but less than
or equal to 32
calendar months.

The Planning
Coordinator did not
perform simulation as
required by part 1.2
within 24 calendar
months (or the next
dynamic local event in
cases where there is
more than 24 months
between events) but
did perform the
simulation in greater
than 32 calendar
months but less than
or equal to 36
calendar months.

months (or the next
dynamic local event in
cases where there is
more than 24 months
between events).

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 30
calendar days of the
written request, but

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 30
calendar days of the
written request, but

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 30
calendar days of the
written request, but

The Reliability
Coordinator or
Transmission Operator
did not provide
requested actual
system behavior data
(or a written response
that it does not have
the requested data) to
a requesting Planning
Coordinator within 75
calendar days;

Page 6 of 12

MOD-033-2 — Steady-State and Dynamic System Model Validation

did provide the data
(or written response
that it does not have
the requested data) in
less than or equal to
45 calendar days.

did provide the data
(or written response
that it does not have
the requested data) in
greater than 45
calendar days but less
than or equal to 60
calendar days.

did provide the data
(or written response
that it does not have
the requested data) in
greater than 60
calendar days but less
than or equal to 75
calendar days.

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Page 7 of 12

OR
The Reliability
Coordinator or
Transmission Operator
provided a written
response that it does
not have the
requested data, but
actually had the data.

MOD-033-2 — Steady-State and Dynamic System Model ValidationApplication Guidelines

Guidelines and Technical Basis
Requirement R1:
The requirement focuses on the results-based outcome of developing a process for and
performing a validation, but does not prescribe a specific method or procedure for the
validation outside of the attributes specified in the requirement. For further information on
suggested validation procedures, see “Procedures for Validation of Powerflow and Dynamics
Cases” produced by the NERC Model Working Group.
The specific process is left to the judgment of the Planning Coordinator, but the Planning
Coordinator is required to develop and include in its process guidelines for evaluating
discrepancies between actual system behavior or response and expected system performance
for determining whether the discrepancies are unacceptable.
For the validation in part 1.1, the state estimator case or other Real-time data should be taken
as close to system peak as possible. However, other snapshots of the system could be used if
deemed to be more appropriate by the Planning Coordinator. While the requirement specifies
“once every 24 calendar months,” entities are encouraged to perform the comparison on a
more frequent basis.
In performing the comparison required in part 1.1, the Planning Coordinator may consider,
among other criteria:
1. System load;
2. Transmission topology and parameters;
3. Voltage at major buses; and
4. Flows on major transmission elements.
The validation in part 1.1 would include consideration of the load distribution and load power
factors (as applicable) used in the power flow models. The validation may be made using
metered load data if state estimator cases are not available. The comparison of system load
distribution and load power factors shall be made on an aggregate company or power flow
zone level at a minimum but may also be made on a bus by bus, load pocket (e.g., within a
Balancing Authority), or smaller area basis as deemed appropriate by the Planning Coordinator.
The scope of dynamics model validation is intended to be limited, for purposes of part 1.2, to
the Planning Coordinator’s planning area, and the intended emphasis under the requirement is
on local events or local phenomena, not the whole Interconnection.
The validation required in part 1.2 may include simulations that are to be compared with actual
system data and may include comparisons of:
•

Voltage oscillations at major buses

•

System frequency (for events with frequency excursions)

•

Real and reactive power oscillations on generating units and major inter-area ties

Page 8 of 12

MOD-033-2 — Steady-State and Dynamic System Model ValidationApplication Guidelines

Determining when a dynamic local event might occur may be unpredictable, and because of the
analytic complexities involved in simulation, the time parameters in part 1.2 specify that the
comparison period of “at least once every 24 calendar months” is intended to both provide for
at least 24 months between dynamic local events used in the comparisons and that
comparisons must be completed within 24 months of the date of the dynamic local event used.
This clarification ensures that PCs will not face a timing scenario that makes it impossible to
comply. If the time referred to the completion time of the comparison, it would be possible for
an event to occur in month 23 since the last comparison, leaving only one month to complete
the comparison. With the 30 day timeframe in Requirement R2 for TOPs or RCs to provide
actual system behavior data (if necessary in the comparison), it would potentially be impossible
to complete the comparison within the 24 month timeframe.
In contrast, the requirement language clarifies that the time frame between dynamic local
events used in the comparisons should be within 24 months of each other (or, as specified at
the end of part 1.2, in the event more than 24 months passes before the next dynamic local
event, the comparison should use the next dynamic local event that occurs). Each comparison
must be completed within 24 months of the dynamic local event used. In this manner, the
potential problem with a “month 23” dynamic local event described above is resolved. For
example, if a PC uses for comparison a dynamic local event occurring on day 1 of month 1, the
PC has 24 calendar months from that dynamic local event’s occurrence to complete the
comparison. If the next dynamic event the PC chooses for comparison occurs in month 23, the
PC has 24 months from that dynamic local event’s occurrence to complete the comparison.
Part 1.3 requires the PC to include guidelines in its documented validation process for
determining when discrepancies in the comparison of simulation results with actual system
results are unacceptable. The PC may develop the guidelines required by parts 1.3 and 1.4
itself, reference other established guidelines, or both. For the power flow comparison, as an
example, this could include a guideline the Planning Coordinator will use that flows on 500 kV
lines should be within 10% or 100 MW, whichever is larger. It could be different percentages or
MW amounts for different voltage levels. Or, as another example, the guideline for voltage
comparisons could be that it must be within 1%. But the guidelines the PC includes within its
documented validation process should be meaningful for the Planning Coordinator’s system.
Guidelines for the dynamic event comparison may be less precise. Regardless, the comparison
should indicate that the conclusions drawn from the two results should be consistent. For
example, the guideline could state that the simulation result will be plotted on the same graph
as the actual system response. Then the two plots could be given a visual inspection to see if
they look similar or not. Or a guideline could be defined such that the rise time of the transient
response in the simulation should be within 20% of the rise time of the actual system response.
As for the power flow guidelines, the dynamic comparison criteria should be meaningful for the
Planning Coordinator’s system.
The guidelines the PC includes in its documented validation process to resolve differences in
Part 1.4 could include direct coordination with the data owner, and, if necessary, through the
provisions of MOD-032-1, Requirement R3 (i.e., the validation performed under this
requirement could identify technical concerns with the data). In other words, while this
standard is focused on validation, results of the validation may identify data provided under the
Page 9 of 12

MOD-033-2 — Steady-State and Dynamic System Model ValidationApplication Guidelines

modeling data standard that needs to be corrected. If a model with estimated data or a generic
model is used for a generator, and the model response does not match the actual response,
then the estimated data should be corrected or a more detailed model should be requested
from the data provider.
While the validation is focused on the Planning Coordinator’s planning area, the model for the
validation should be one that contains a wider area of the Interconnection than the Planning
Coordinator’s area. If the simulations can be made to match the actual system responses by
reasonable changes to the data in the Planning Coordinator’s area, then the Planning
Coordinator should make those changes in coordination with the data provider. However, for
some disturbances, the data in the Planning Coordinator’s area may not be what is causing the
simulations to not match actual responses. These situations should be reported to the Electric
Reliability Organization (ERO). The guidelines the Planning Coordinator includes under Part 1.4
could cover these situations.
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:
In FERC Order No. 693, paragraph 1210, the Commission directed inclusion of “a requirement
that the models be validated against actual system responses.” Furthermore, the Commission
directs in paragraph 1211, “that actual system events be simulated and if the model output is
not within the accuracy required, the model shall be modified to achieve the necessary
accuracy.” Paragraph 1220 similarly directs validation against actual system responses relative
to dynamics system models. In FERC Order 890, paragraph 290, the Commission states that
“the models should be updated and benchmarked to actual events.” Requirement R1 addresses
these directives.
Requirement R1 requires the Planning Coordinator to implement a documented data validation
process to validate data in the Planning Coordinator’s portion of the existing system in the
steady-state and dynamic models to compare performance against expected behavior or
response, which is consistent with the Commission directives. The validation of the full
Interconnection-wide cases is left up to the Electric Reliability Organization (ERO) or its
designees, and is not addressed by this standard. The following items were chosen for the
validation requirement:
A. Comparison of performance of the existing system in a planning power flow model to actual
system behavior; and
B. Comparison of the performance of the existing system in a planning dynamics model to
actual system response.

Page 10 of 12

MOD-033-2 — Steady-State and Dynamic System Model ValidationApplication Guidelines

Implementation of these validations will result in more accurate power flow and dynamic
models. This, in turn, should result in better correlation between system flows and voltages
seen in power flow studies and the actual values seen by system operators during outage
conditions. Similar improvements should be expected for dynamics studies, such that the
results will more closely match the actual responses of the power system to disturbances.
Validation of model data is a good utility practice, but it does not easily lend itself to Reliability
Standards requirement language. Furthermore, it is challenging to determine specifications for
thresholds of disturbances that should be validated and how they are determined. Therefore,
this requirement focuses on the Planning Coordinator performing validation pursuant to its
process, which must include the attributes listed in parts 1.1 through 1.4, without specifying the
details of “how” it must validate, which is necessarily dependent upon facts and circumstances.
Other validations are best left to guidance rather than standard requirements.
Rationale for R2:
The Planning Coordinator will need actual system behavior data in order to perform the
validations required in R1. The Reliability Coordinator or Transmission Operator may have this
data. Requirement R2 requires the Reliability Coordinator and Transmission Operator to supply
actual system data, if it has the data, to any requesting Planning Coordinator for purposes of
model validation under Requirement R1.
This could also include information the Reliability Coordinator or Transmission Operator has at
a field site. For example, if a PMU or DFR is at a generator site and it is recording the
disturbance, the Reliability Coordinator or Transmission Operator would typically have that
data.

Version History
Version

Date

Action

1

February 6,
2014

Adopted by the NERC Board of
Trustees.

1

May 1, 2014

FERC Order issued approving
MOD-033-1.

Change Tracking
Developed as a new
standard for system
validation to address
outstanding directives
from FERC Order No. 693
and recommendations
from several other
sources.

Page 11 of 12

MOD-033-2 — Steady-State and Dynamic System Model ValidationApplication Guidelines

2

Adopted by the NERC Board of
Trustees.

Page 12 of 12

NUC-001-4— Nuclear Plant Interface Coordination

A. Introduction
1.

Title:

Nuclear Plant Interface Coordination

2.

Number:

NUC-001-4

3.

Purpose: This standard requires coordination between Nuclear Plant Generator
Operators and Transmission Entities for the purpose of ensuring nuclear plant safe
operation and shutdown.

4.

Applicability:
4.1. Functional Entities:
4.1.1 Nuclear Plant Generator Operators.
4.2. Transmission Entities shall mean all entities that are responsible for providing
services related to Nuclear Plant Interface Requirements (NPIRs). Such entities
may include one or more of the following:
4.2.1 Transmission Operators.
4.2.2 Transmission Owners.
4.2.3 Transmission Planners.
4.2.4 Transmission Service Providers.
4.2.5 Balancing Authorities.
4.2.6 Reliability Coordinators.
4.2.7 Planning Coordinators.
4.2.8 Distribution Providers.
4.2.9 Generator Owners.
4.2.10 Generator Operators.
Effective Date: See Implementation Plan.

Draft 2 of NUC-001-4
January 2020

Page 1 of 16

NUC-001-4— Nuclear Plant Interface Coordination

B. Requirements and Measures
R1.

The Nuclear Plant Generator Operator shall provide the proposed NPIRs in writing to
the applicable Transmission Entities and shall verify receipt. [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning ]

M1. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, provide a copy of the transmittal and receipt of transmittal of
the proposed NPIRs to the responsible Transmission Entities.
R2.

The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
have in effect one or more Agreements 1 that include mutually agreed to NPIRs and
document how the Nuclear Plant Generator Operator and the applicable Transmission
Entities shall address and implement these NPIRs. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning ]

M2. The Nuclear Plant Generator Operator and each Transmission Entity shall each have a
copy of the currently effective Agreement(s) which document how the Nuclear Plant
Generator Operator and the applicable Transmission Entities address and implement
the NPIRs available for inspection upon request of the Compliance Enforcement
Authority.
R3.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall incorporate the NPIRs into their planning analyses of the
electric system and shall communicate the results of these analyses to the Nuclear
Plant Generator Operator.: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning ]

M3. Each Transmission Entity responsible for planning analyses in accordance with the
Agreement shall, upon request of the Compliance Enforcement Authority, provide a
copy of the planning analyses results transmitted to the Nuclear Plant Generator
Operator, showing incorporation of the NPIRs. The Compliance Enforcement
Authority shall refer to the Agreements developed in accordance with this standard
for specific requirements.
R4.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall [Violation Risk Factor: High] [Time Horizon: Operations
Planning and Real-time Operations]
4.1. Incorporate the NPIRs into their operating analyses of the electric system.
4.2. Operate the electric system to meet the NPIRs.

Agreements may include mutually agreed upon procedures or protocols in effect between entities or between departments of
a vertically integrated system.

1

Draft 2 of NUC-001-4
January 2020

Page 2 of 16

NUC-001-4— Nuclear Plant Interface Coordination

4.3. Inform the Nuclear Plant Generator Operator when the ability to assess the
operation of the electric system affecting NPIRs is lost.
M4. Each Transmission Entity responsible for operating the electric system in accordance
with the Agreement shall demonstrate or provide evidence of the following, upon
request of the Compliance Enforcement Authority:

R5.

•

The NPIRs have been incorporated into the current operating analysis of the
electric system. (Requirement 4.1)

•

The electric system was operated to meet the NPIRs. (Requirement 4.2)

•

The Transmission Entity informed the Nuclear Plant Generator Operator when it
became aware it lost the capability to assess the operation of the electric system
affecting the NPIRs

Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall operate the nuclear plant to meet the NPIRs. [Violation Risk
Factor: High] [Time Horizon: Operations Planning and Real-time Operations ]

M5. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, demonstrate or provide evidence that the nuclear power
plant is being operated consistent with the NPIRs.
R6.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities and the Nuclear Plant Generator Operator shall coordinate
outages and maintenance activities which affect the NPIRs. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]

M6. The Transmission Entities and Nuclear Plant Generator Operator shall, upon request
of the Compliance Enforcement Authority, provide evidence of the coordination
between the Transmission Entities and the Nuclear Plant Generator Operator
regarding outages and maintenance activities which affect the NPIRs.
R7.

Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall inform the applicable Transmission Entities of actual or
proposed changes to nuclear plant design (e.g., protective relay setpoints),
configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]

M7. The Nuclear Plant Generator Operator shall provide evidence that it informed the
applicable Transmission Entities of changes to nuclear plant design (e.g., protective
relay setpoints), configuration, operations, limits, or capabilities that may impact the
ability of the Transmission Entities to meet the NPIRs.
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NUC-001-4— Nuclear Plant Interface Coordination

R8.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall inform the Nuclear Plant Generator Operator of actual or
proposed changes to electric system design (e.g., protective relay setpoints),
configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]

M8. The Transmission Entities shall each provide evidence that the entities informed the
Nuclear Plant Generator Operator of changes to electric system design (e.g.,
protective relay setpoints), configuration, operations, limits, or capabilities that may
impact the ability of the Nuclear Plant Generator Operator to meet the NPIRs.
R9.

The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
include the following elements in aggregate within the Agreement(s) identified in R2.
•

Where multiple Agreements with a single Transmission Entity are put into effect,
the R9 elements must be addressed in aggregate within the Agreements;
however, each Agreement does not have to contain each element. The Nuclear
Plant Generator Operator and the Transmission Entity are responsible for ensuring
all the R9 elements are addressed in aggregate within the Agreements.

•

Where Agreements with multiple Transmission Entities are required, the Nuclear
Plant Generator Operator is responsible for ensuring all the R9 elements are
addressed in aggregate within the Agreements with the Transmission Entities. The
Agreements with each Transmission Entity do not have to contain each element;
however, the Agreements with the multiple Transmission Entities, in the
aggregate, must address all R9 elements. For each Agreement(s), the Nuclear
Plant Generator Operator and the Transmission Entity are responsible to ensure
the Agreement(s) contain(s) the elements of R9 applicable to that Transmission
Entity. : [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

9.1. Retired. [Note: Part 9.1 was retired under the Paragraph 81 project. The NUC SDT
proposes to leave this Part blank to avoid renumbering Requirement parts that
would impact existing agreements throughout the industry.]
9.2. Technical requirements and analysis:
9.2.1. Identification of parameters, limits, configurations, and operating
scenarios included in the NPIRs and, as applicable, procedures for
providing any specific data not provided within the Agreement.
9.2.2. Identification of facilities, components, and configuration restrictions that
are essential for meeting the NPIRs.

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NUC-001-4— Nuclear Plant Interface Coordination

9.2.3. Types of planning and operational analyses performed specifically to
support the NPIRs, including the frequency of studies and types of
Contingencies and scenarios required.
9.3. Operations and maintenance coordination
9.3.1. Designation of ownership of electrical facilities at the interface between
the electric system and the nuclear plant and responsibilities for
operational control coordination and maintenance of these facilities.
9.3.2. Identification of any maintenance requirements for equipment not
owned or controlled by the Nuclear Plant Generator Operator that are
necessary to meet the NPIRs.
9.3.3. Coordination of testing, calibration and maintenance of on-site and offsite power supply systems and related components.
9.3.4. Provisions to address mitigating actions needed to avoid violating NPIRs
and to address periods when responsible Transmission Entity loses the
ability to assess the capability of the electric system to meet the NPIRs.
These provisions shall include responsibility to notify the Nuclear Plant
Generator Operator within a specified time frame.
9.3.5. Provision for considering, within the restoration process, the
requirements and urgency of a nuclear plant that has lost all off-site and
on-site AC power.
9.3.6. Coordination of physical and cyber security protection at the nuclear
plant interface to ensure each asset is covered under at least one entity’s
plan.
9.3.7. Coordination of the NPIRs with transmission system Remedial Action
Schemes and any programs that reduce or shed load based on
underfrequency or undervoltage.
9.4. Communications and training Administrative elements:
9.4.1. Provisions for communications affecting the NPIRs between the Nuclear
Plant Generator Operator and Transmission Entities, including
communications protocols, notification time requirements, and
definitions of applicable unique terms.
9.4.2. Provisions for coordination during an off-normal or emergency event
affecting the NPIRs, including the need to provide timely information
explaining the event, an estimate of when the system will be returned to
a normal state, and the actual time the system is returned to normal.
9.4.3. Provisions for coordinating investigations of causes of unplanned events
affecting the NPIRs and developing solutions to minimize future risk of
such events.

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NUC-001-4— Nuclear Plant Interface Coordination

9.4.4. Provisions for supplying information necessary to report to government
agencies, as related to NPIRs.
9.4.5. Provisions for personnel training, as related to NPIRs.
M9. The Nuclear Plant Generator Operator shall have a copy of the Agreement(s)
addressing the elements in Requirement 9 available for inspection upon request of the
Compliance Enforcement Authority. Each Transmission Entity shall have a copy of the
Agreement(s) addressing the elements in Requirement 9 for which it is responsible available
for inspection upon request of the Compliance Enforcement Authority.

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C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints Text
1.3. Data Retention
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
•

For Measure 1, the Nuclear Plant Generator Operator shall keep its latest
transmittals and receipts.

•

For Measure 2, the Nuclear Plant Generator Operator and each
Transmission Entity shall have its current, in-force Agreement.

•

For Measure 3, the Transmission Entity shall have the latest planning
analysis results.

•

For Measures 4, 6 and 8, the Transmission Entity shall keep evidence for
two years plus current.

•

For Measures 5, 6 and 7, the Nuclear Plant Generator Operator shall keep
evidence for two years plus current.

If a Responsible Entity is found non-compliant it shall keep information related to
the noncompliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None

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NUC-001-4— Nuclear Plant Interface Coordination

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

R1

R2

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Medium The Nuclear Plant
Generator Operator
provided the NPIRs to
the applicable entities
but did not verify
receipt.

Medium N/A

Moderate VSL

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIR to one
of the applicable
entities unless there
was only one entity.

N/A

High VSL

Severe VSL

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIRs to
two of the applicable
entities unless there
were only two
entities.

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIRs to
more than two of
applicable entities.

N/A

The Nuclear Plant
Generator Operator or
the applicable
Transmission Entity
does not have in effect
one or more
agreements that
include mutually
agreed to NPIRs and

OR
For a particular
nuclear power plant, if
the number of
possible applicable
transmission entities is
equal to the number
of applicable
transmission entities
not provided NPIRs

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

document the
implementation of the
NPIRs.
R3

Medium N/A

The responsible entity
incorporated the
NPIRs into its planning
analyses but did not
communicate the
results to the Nuclear
Plant Generator
Operator.

N/A

The responsible entity
did not incorporate
the NPIRs into its
planning analyses of
the electric system.

R4

High

N/A

The responsible entity
did not comply with
Requirement R4, Part
4.3.

The responsible entity
did not comply with
Requirement R4, Part
R4.1.

The responsible entity
did not comply with
Requirement R4, Part
R4.2.

R5

High

N/A

N/A

N/A

The Nuclear Plant
Generator Operator
failed to operate per
the NPIRs developed
in accordance with
this standard.

R6

Medium N/A

The Nuclear Plant
Generator Operator or
Transmission Entity
failed to provide

The Nuclear Plant
N/A
Generator Operator or
Transmission Entity
failed to coordinate

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

outage or
maintenance
schedules to the
appropriate parties as
described in the
agreement or on a
time period consistent
with the agreements.

High VSL

Severe VSL

one or more outages
or maintenance
activities in
accordance the
requirements of the
agreements.

R7

High

The Nuclear Plant
N/A
Generator Operator
did not inform the
applicable
Transmission Entities
of proposed changes
to nuclear plant design
(e.g. protective relay
setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

The Nuclear Plant
Generator Operator
did not inform the
applicable
Transmission Entities
of actual changes to
nuclear plant design
(e.g. protective relay
setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

The Nuclear Plant
Generator Operator
did not inform the
applicable
Transmission Entities
of actual changes to
nuclear plant design
(e.g., protective relay
setpoints),
configuration,
operations, limits or
capabilities that
directly impact the
ability of the electric
system to meet the
NPIRs.

R8

High

The applicable
Transmission Entities
did not inform the

The applicable
Transmission Entities
did not inform the

The applicable
Transmission Entities
did not inform the

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N/A

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

Nuclear Plant
Generator Operator of
proposed changes to
transmission system
design, configuration
(e.g. protective relay
setpoints), operations,
limits, or capabilities
that may impact the
ability of the electric
system to meet the
NPIRs.
R9

Draft 2 of NUC-001-4
January 2020

Medium

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include up to
20% of the combined
sub-components in
Requirement R9 Parts
9.2, 9.3 and 9.4
applicable to that
entity.

High VSL

Severe VSL

Nuclear Plant
Generator Operator of
actual changes to
transmission system
design (e.g. protective
relay setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

Nuclear Plant
Generator Operator of
actual changes to
transmission system
design (e.g. protective
relay setpoints),
configuration,
operations, limits, or
capabilities that
directly impacts the
ability of the electric
system to meet the
NPIRs.

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include
greater than 20%, but
less than 40% of the
combined subcomponents in
Requirement R9 Parts
9.2, 9.3 and 9.4

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include 40%
or more of the
combined subcomponents in
Requirement R9 Parts
9.2, 9.3 and 9.4

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

applicable to the
entity.

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Severe VSL

applicable to the
entity.

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NUC-001-4— Nuclear Plant Interface Coordination

D. Regional Variances
The design basis for Canadian (CANDU) nuclear power plants (NPPs) does not result in the
same licensing requirements as U.S. NPPs. Nuclear Regulatory Commission (NRC) design
criteria specifies that in addition to emergency on-site electrical power, electrical power
from the electric network also be provided to permit safe shutdown. There are no
equivalent Canadian Regulatory requirements for electrical power from the electric network
to be provided to permit safe shutdown. Therefore the definition of Nuclear Plant Licensing
Requirements (NPLR) for Canadian CANDU NPPs will be as follows:
Canadian Nuclear Plant Licensing Requirements (CNPLR) are requirements included in the
design basis of the nuclear plant and are statutorily mandated for the operation of the
plant; when used in this standard, NPLR shall mean nuclear power plant licensing
requirements for avoiding preventable challenges to nuclear safety as a result of an electric
system disturbance, transient, or condition.

E. Interpretations
None

F. Associated Documents
None

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NUC-001-4— Nuclear Plant Interface Coordination

Version History
Version

Date

Action

Change Tracking

1

May 2, 2007

Approved by Board of
Trustees

2

August 5, 2009

Adopted by Board of Trustees Revised. Modifications
for Order 716 to
Requirement R9.3.5 and
footnote 1;
modifications to bring
compliance elements
into conformance with
the latest version of the
ERO Rules of Procedure.

2

January 22, 2010

Approved by FERC on January
21, 2010. Added Effective
Date

2

February 7, 2013

R9.1, R9.1.1, R9.1.2, R9.1.3,
and R9.1.4 and associated
elements approved by NERC
Board of Trustees for
retirement as part of the
Paragraph 81 project (Project
2013-02) pending applicable
regulatory approval.

2

November 21, 2013 R9.1, R9.1.1, R9.1.2, R9.1.3,
and R9.1.4 and associated
elements approved by FERC
for retirement as part of the
Paragraph 81 project (Project
2013-02)

2.1

April 11, 2012

2.1

September 9, 2013

Draft 2 of NUC-001-4
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New

Update

Errata approved by the
Errata associated with
Standards Committee;
Project 2007-17
(Capitalized “Protection
System” in accordance with
Implementation Plan for
Project 2007-17 approval of
revised definition of
“Protection System”)
Informational filing submitted
to reflect the revised

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NUC-001-4— Nuclear Plant Interface Coordination

definition of Protection
System in accordance with
the Implementation Plan for
the revised term.
3

March 2014

Modifications to implement
the recommendations of the
five-year review of NUC-001,
which was accepted by the
Standards Committee on
October 17, 2013.

3

August 14, 2014

Adopted by the NERC Board
of Trustees

3

November 4, 2014

FERC letter order issued
approving NUC-001-3

4

Revision

Adopted by the NERC Board
of Trustees

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 R5:
The NUC FYRT recommended R5 be revised for consistency with R4 and to clarify that nuclear
plants must be operated to meet the Nuclear Plant Interface Requirements.
Rationale for R7 and R8:
The NUC FYRT recommended deleting “Protection Systems” in Requirements R7 and R8 since it
is a subset of the "nuclear plant design" and "electric system design" elements currently
contained in R7 and R8 respectively; and adding a parenthetical clause (e.g. protective
setpoints) to R7 following "nuclear plant design" and parenthetical clause (e.g. relay setpoints)
to R8 following "electric system design."
Rationale for R9:
The NUC FYRT recommended that R9 be revised to clarify that all agreements do not have to
discuss each of the elements in R9, but that the sum total of the agreements need to address
the elements. In addition, for clarity in Part 9.4.1, the NUC FYRT recommended that "affecting
the NPIRs" be inserted following "Provisions for communications" and "applicable unique" be
inserted following ""definitions of."

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NUC-001-4— Nuclear Plant Interface Coordination

Rationale for R9.3.7:
The term “Special Protection Systems” (SPS) was replaced with “Remedial Action Schemes”
(RAS) in order to align with other current NERC standards development work in Project 201005.2: Special Protection Systems. Project 2010-05.2 has proposed to replace SPS with RAS
throughout all of the NERC Standards in order to move to the use of a single term. RAS and SPS
have the same definition in the NERC Glossary of Terms.

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NUC-001-4— Nuclear Plant Interface Coordination

A. Introduction
1.

Title:

Nuclear Plant Interface Coordination

2.

Number:

NUC-001-4

3.

Purpose: This standard requires coordination between Nuclear Plant Generator
Operators and Transmission Entities for the purpose of ensuring nuclear plant safe
operation and shutdown.

4.

Applicability:
4.1. Functional Entities:
4.1.1 Nuclear Plant Generator Operators.
4.2. Transmission Entities shall mean all entities that are responsible for providing
services related to Nuclear Plant Interface Requirements (NPIRs). Such entities
may include one or more of the following:
4.2.1 Transmission Operators.
4.2.2 Transmission Owners.
4.2.3 Transmission Planners.
4.2.4 Transmission Service Providers.
4.2.5 Balancing Authorities.
4.2.6 Reliability Coordinators.
4.2.7 Planning Coordinators.
4.2.8 Distribution Providers.
4.2.9 Generator Owners.
4.2.10 Generator Operators.
Proposed Effective Date: See Implementation Plan.

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B. Requirements and Measures
R1.

The Nuclear Plant Generator Operator shall provide the proposed NPIRs in writing to
the applicable Transmission Entities and shall verify receipt. [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning ]

M1. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, provide a copy of the transmittal and receipt of transmittal of
the proposed NPIRs to the responsible Transmission Entities.
R2.

The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
have in effect one or more Agreements 1 that include mutually agreed to NPIRs and
document how the Nuclear Plant Generator Operator and the applicable Transmission
Entities shall address and implement these NPIRs. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning ]

M2. The Nuclear Plant Generator Operator and each Transmission Entity shall each have a
copy of the currently effective Agreement(s) which document how the Nuclear Plant
Generator Operator and the applicable Transmission Entities address and implement
the NPIRs available for inspection upon request of the Compliance Enforcement
Authority.
R3.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall incorporate the NPIRs into their planning analyses of the
electric system and shall communicate the results of these analyses to the Nuclear
Plant Generator Operator.: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning ]

M3. Each Transmission Entity responsible for planning analyses in accordance with the
Agreement shall, upon request of the Compliance Enforcement Authority, provide a
copy of the planning analyses results transmitted to the Nuclear Plant Generator
Operator, showing incorporation of the NPIRs. The Compliance Enforcement
Authority shall refer to the Agreements developed in accordance with this standard
for specific requirements.
R4.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall [Violation Risk Factor: High] [Time Horizon: Operations
Planning and Real-time Operations]
4.1. Incorporate the NPIRs into their operating analyses of the electric system.
4.2. Operate the electric system to meet the NPIRs.

Agreements may include mutually agreed upon procedures or protocols in effect between entities or between departments of
a vertically integrated system.

1

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NUC-001-4— Nuclear Plant Interface Coordination

4.3. Inform the Nuclear Plant Generator Operator when the ability to assess the
operation of the electric system affecting NPIRs is lost.
M4. Each Transmission Entity responsible for operating the electric system in accordance
with the Agreement shall demonstrate or provide evidence of the following, upon
request of the Compliance Enforcement Authority:

R5.

•

The NPIRs have been incorporated into the current operating analysis of the
electric system. (Requirement 4.1)

•

The electric system was operated to meet the NPIRs. (Requirement 4.2)

•

The Transmission Entity informed the Nuclear Plant Generator Operator when it
became aware it lost the capability to assess the operation of the electric system
affecting the NPIRs

Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall operate the nuclear plant to meet the NPIRs. [Violation Risk
Factor: High] [Time Horizon: Operations Planning and Real-time Operations ]

M5. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, demonstrate or provide evidence that the nuclear power
plant is being operated consistent with the NPIRs.
R6.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities and the Nuclear Plant Generator Operator shall coordinate
outages and maintenance activities which affect the NPIRs. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]

M6. The Transmission Entities and Nuclear Plant Generator Operator shall, upon request
of the Compliance Enforcement Authority, provide evidence of the coordination
between the Transmission Entities and the Nuclear Plant Generator Operator
regarding outages and maintenance activities which affect the NPIRs.
R7.

Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall inform the applicable Transmission Entities of actual or
proposed changes to nuclear plant design (e.g., protective relay setpoints),
configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]

M7. The Nuclear Plant Generator Operator shall provide evidence that it informed the
applicable Transmission Entities of changes to nuclear plant design (e.g., protective
relay setpoints), configuration, operations, limits, or capabilities that may impact the
ability of the Transmission Entities to meet the NPIRs.
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NUC-001-4— Nuclear Plant Interface Coordination

R8.

Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall inform the Nuclear Plant Generator Operator of actual or
proposed changes to electric system design (e.g., protective relay setpoints),
configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]

M8. The Transmission Entities shall each provide evidence that the entities informed the
Nuclear Plant Generator Operator of changes to electric system design (e.g.,
protective relay setpoints), configuration, operations, limits, or capabilities that may
impact the ability of the Nuclear Plant Generator Operator to meet the NPIRs.
R9.

The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
include the following elements in aggregate within the Agreement(s) identified in R2.
•

Where multiple Agreements with a single Transmission Entity are put into effect,
the R9 elements must be addressed in aggregate within the Agreements;
however, each Agreement does not have to contain each element. The Nuclear
Plant Generator Operator and the Transmission Entity are responsible for ensuring
all the R9 elements are addressed in aggregate within the Agreements.

•

Where Agreements with multiple Transmission Entities are required, the Nuclear
Plant Generator Operator is responsible for ensuring all the R9 elements are
addressed in aggregate within the Agreements with the Transmission Entities. The
Agreements with each Transmission Entity do not have to contain each element;
however, the Agreements with the multiple Transmission Entities, in the
aggregate, must address all R9 elements. For each Agreement(s), the Nuclear
Plant Generator Operator and the Transmission Entity are responsible to ensure
the Agreement(s) contain(s) the elements of R9 applicable to that Transmission
Entity. : [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

9.1. Retired. [Note: Part 9.1 was retired under the Paragraph 81 project. The NUC SDT
proposes to leave this Part blank to avoid renumbering Requirement parts that
would impact existing agreements throughout the industry.]
9.2. Technical requirements and analysis:
9.2.1. Identification of parameters, limits, configurations, and operating
scenarios included in the NPIRs and, as applicable, procedures for
providing any specific data not provided within the Agreement.
9.2.2. Identification of facilities, components, and configuration restrictions that
are essential for meeting the NPIRs.

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9.2.3. Types of planning and operational analyses performed specifically to
support the NPIRs, including the frequency of studies and types of
Contingencies and scenarios required.
9.3. Operations and maintenance coordination
9.3.1. Designation of ownership of electrical facilities at the interface between
the electric system and the nuclear plant and responsibilities for
operational control coordination and maintenance of these facilities.
9.3.2. Identification of any maintenance requirements for equipment not
owned or controlled by the Nuclear Plant Generator Operator that are
necessary to meet the NPIRs.
9.3.3. Coordination of testing, calibration and maintenance of on-site and offsite power supply systems and related components.
9.3.4. Provisions to address mitigating actions needed to avoid violating NPIRs
and to address periods when responsible Transmission Entity loses the
ability to assess the capability of the electric system to meet the NPIRs.
These provisions shall include responsibility to notify the Nuclear Plant
Generator Operator within a specified time frame.
9.3.5. Provision for considering, within the restoration process, the
requirements and urgency of a nuclear plant that has lost all off-site and
on-site AC power.
9.3.6. Coordination of physical and cyber security protection at the nuclear
plant interface to ensure each asset is covered under at least one entity’s
plan.
9.3.7. Coordination of the NPIRs with transmission system Remedial Action
Schemes and any programs that reduce or shed load based on
underfrequency or undervoltage.
9.4. Communications and training Administrative elements:
9.4.1. Provisions for communications affecting the NPIRs between the Nuclear
Plant Generator Operator and Transmission Entities, including
communications protocols, notification time requirements, and
definitions of applicable unique terms.
9.4.2. Provisions for coordination during an off-normal or emergency event
affecting the NPIRs, including the need to provide timely information
explaining the event, an estimate of when the system will be returned to
a normal state, and the actual time the system is returned to normal.
9.4.3. Provisions for coordinating investigations of causes of unplanned events
affecting the NPIRs and developing solutions to minimize future risk of
such events.

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NUC-001-4— Nuclear Plant Interface Coordination

9.4.4. Provisions for supplying information necessary to report to government
agencies, as related to NPIRs.
9.4.5. Provisions for personnel training, as related to NPIRs.
M9. The Nuclear Plant Generator Operator shall have a copy of the Agreement(s)
addressing the elements in Requirement 9 available for inspection upon request of the
Compliance Enforcement Authority. Each Transmission Entity shall have a copy of the
Agreement(s) addressing the elements in Requirement 9 for which it is responsible available
for inspection upon request of the Compliance Enforcement Authority.

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NUC-001-4— Nuclear Plant Interface Coordination

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints Text
1.3. Data Retention
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
•

For Measure 1, the Nuclear Plant Generator Operator shall keep its latest
transmittals and receipts.

•

For Measure 2, the Nuclear Plant Generator Operator and each
Transmission Entity shall have its current, in-force Agreement.

•

For Measure 3, the Transmission Entity shall have the latest planning
analysis results.

•

For Measures 4, 6 and 8, the Transmission Entity shall keep evidence for
two years plus current.

•

For Measures 5, 6 and 7, the Nuclear Plant Generator Operator shall keep
evidence for two years plus current.

If a Responsible Entity is found non-compliant it shall keep information related to
the noncompliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None

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NUC-001-4— Nuclear Plant Interface Coordination

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

R1

R2

Draft 1 2 of NUC-001-4
October January 201920

Medium The Nuclear Plant
Generator Operator
provided the NPIRs to
the applicable entities
but did not verify
receipt.

Medium N/A

Moderate VSL

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIR to one
of the applicable
entities unless there
was only one entity.

N/A

High VSL

Severe VSL

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIRs to
two of the applicable
entities unless there
were only two
entities.

The Nuclear Plant
Generator Operator
did not provide the
proposed NPIRs to
more than two of
applicable entities.

N/A

The Nuclear Plant
Generator Operator or
the applicable
Transmission Entity
does not have in effect
one or more
agreements that
include mutually
agreed to NPIRs and

OR
For a particular
nuclear power plant, if
the number of
possible applicable
transmission entities is
equal to the number
of applicable
transmission entities
not provided NPIRs

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

document the
implementation of the
NPIRs.
R3

Medium N/A

The responsible entity
incorporated the
NPIRs into its planning
analyses but did not
communicate the
results to the Nuclear
Plant Generator
Operator.

N/A

The responsible entity
did not incorporate
the NPIRs into its
planning analyses of
the electric system.

R4

High

N/A

The responsible entity
did not comply with
Requirement R4, Part
4.3.

The responsible entity
did not comply with
Requirement R4, Part
R4.1.

The responsible entity
did not comply with
Requirement R4, Part
R4.2.

R5

High

N/A

N/A

N/A

The Nuclear Plant
Generator Operator
failed to operate per
the NPIRs developed
in accordance with
this standard.

R6

Medium N/A

The Nuclear Plant
Generator Operator or
Transmission Entity
failed to provide

The Nuclear Plant
N/A
Generator Operator or
Transmission Entity
failed to coordinate

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

outage or
maintenance
schedules to the
appropriate parties as
described in the
agreement or on a
time period consistent
with the agreements.

High VSL

Severe VSL

one or more outages
or maintenance
activities in
accordance the
requirements of the
agreements.

R7

High

The Nuclear Plant
N/A
Generator Operator
did not inform the
applicable
Transmission Entities
of proposed changes
to nuclear plant design
(e.g. protective relay
setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

The Nuclear Plant
Generator Operator
did not inform the
applicable
Transmission Entities
of actual changes to
nuclear plant design
(e.g. protective relay
setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

The Nuclear Plant
Generator Operator
did not inform the
applicable
Transmission Entities
of actual changes to
nuclear plant design
(e.g., protective relay
setpoints),
configuration,
operations, limits or
capabilities that
directly impact the
ability of the electric
system to meet the
NPIRs.

R8

High

The applicable
Transmission Entities
did not inform the

The applicable
Transmission Entities
did not inform the

The applicable
Transmission Entities
did not inform the

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N/A

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

Nuclear Plant
Generator Operator of
proposed changes to
transmission system
design, configuration
(e.g. protective relay
setpoints), operations,
limits, or capabilities
that may impact the
ability of the electric
system to meet the
NPIRs.
R9

Draft 1 2 of NUC-001-4
October January 201920

Medium

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include up to
20% of the combined
sub-components in
Requirement R9 Parts
9.2, 9.3 and 9.4
applicable to that
entity.

High VSL

Severe VSL

Nuclear Plant
Generator Operator of
actual changes to
transmission system
design (e.g. protective
relay setpoints),
configuration,
operations, limits, or
capabilities that may
impact the ability of
the electric system to
meet the NPIRs.

Nuclear Plant
Generator Operator of
actual changes to
transmission system
design (e.g. protective
relay setpoints),
configuration,
operations, limits, or
capabilities that
directly impacts the
ability of the electric
system to meet the
NPIRs.

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include
greater than 20%, but
less than 40% of the
combined subcomponents in
Requirement R9 Parts
9.2, 9.3 and 9.4

The Agreement(s)
identified in R2.
between the Nuclear
Plant Generator
Operator and the
applicable
Transmission Entity
failed to include 40%
or more of the
combined subcomponents in
Requirement R9 Parts
9.2, 9.3 and 9.4

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NUC-001-4— Nuclear Plant Interface Coordination

R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

applicable to the
entity.

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Severe VSL

applicable to the
entity.

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NUC-001-4— Nuclear Plant Interface Coordination

D. Regional Variances
The design basis for Canadian (CANDU) nuclear power plants (NPPs) does not result in the
same licensing requirements as U.S. NPPs. Nuclear Regulatory Commission (NRC) design
criteria specifies that in addition to emergency on-site electrical power, electrical power
from the electric network also be provided to permit safe shutdown. There are no
equivalent Canadian Regulatory requirements for electrical power from the electric network
to be provided to permit safe shutdown. Therefore the definition of Nuclear Plant Licensing
Requirements (NPLR) for Canadian CANDU NPPs will be as follows:
Canadian Nuclear Plant Licensing Requirements (CNPLR) are requirements included in the
design basis of the nuclear plant and are statutorily mandated for the operation of the
plant; when used in this standard, NPLR shall mean nuclear power plant licensing
requirements for avoiding preventable challenges to nuclear safety as a result of an electric
system disturbance, transient, or condition.

E. Interpretations
None

F. Associated Documents
None

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NUC-001-4— Nuclear Plant Interface Coordination

Version History
Version

Date

Action

Change Tracking

1

May 2, 2007

Approved by Board of
Trustees

2

August 5, 2009

Adopted by Board of Trustees Revised. Modifications
for Order 716 to
Requirement R9.3.5 and
footnote 1;
modifications to bring
compliance elements
into conformance with
the latest version of the
ERO Rules of Procedure.

2

January 22, 2010

Approved by FERC on January
21, 2010. Added Effective
Date

2

February 7, 2013

R9.1, R9.1.1, R9.1.2, R9.1.3,
and R9.1.4 and associated
elements approved by NERC
Board of Trustees for
retirement as part of the
Paragraph 81 project (Project
2013-02) pending applicable
regulatory approval.

2

November 21, 2013 R9.1, R9.1.1, R9.1.2, R9.1.3,
and R9.1.4 and associated
elements approved by FERC
for retirement as part of the
Paragraph 81 project (Project
2013-02)

2.1

April 11, 2012

2.1

September 9, 2013

Draft 1 2 of NUC-001-4
October January 20192020

New

Update

Errata approved by the
Errata associated with
Standards Committee;
Project 2007-17
(Capitalized “Protection
System” in accordance with
Implementation Plan for
Project 2007-17 approval of
revised definition of
“Protection System”)
Informational filing submitted
to reflect the revised

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NUC-001-4— Nuclear Plant Interface Coordination

definition of Protection
System in accordance with
the Implementation Plan for
the revised term.
3

March 2014

Modifications to implement
the recommendations of the
five-year review of NUC-001,
which was accepted by the
Standards Committee on
October 17, 2013.

3

August 14, 2014

Adopted by the NERC Board
of Trustees

3

November 4, 2014

FERC letter order issued
approving NUC-001-3

4

Revision

Adopted by the NERC Board
of Trustees

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 R5:
The NUC FYRT recommended R5 be revised for consistency with R4 and to clarify that nuclear
plants must be operated to meet the Nuclear Plant Interface Requirements.
Rationale for R7 and R8:
The NUC FYRT recommended deleting “Protection Systems” in Requirements R7 and R8 since it
is a subset of the "nuclear plant design" and "electric system design" elements currently
contained in R7 and R8 respectively; and adding a parenthetical clause (e.g. protective
setpoints) to R7 following "nuclear plant design" and parenthetical clause (e.g. relay setpoints)
to R8 following "electric system design."
Rationale for R9:
The NUC FYRT recommended that R9 be revised to clarify that all agreements do not have to
discuss each of the elements in R9, but that the sum total of the agreements need to address
the elements. In addition, for clarity in Part 9.4.1, the NUC FYRT recommended that "affecting
the NPIRs" be inserted following "Provisions for communications" and "applicable unique" be
inserted following ""definitions of."

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NUC-001-4— Nuclear Plant Interface Coordination

Rationale for R9.3.7:
The term “Special Protection Systems” (SPS) was replaced with “Remedial Action Schemes”
(RAS) in order to align with other current NERC standards development work in Project 201005.2: Special Protection Systems. Project 2010-05.2 has proposed to replace SPS with RAS
throughout all of the NERC Standards in order to move to the use of a single term. RAS and SPS
have the same definition in the NERC Glossary of Terms.

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NUC-001-34— Nuclear Plant Interface Coordination

A. Introduction
1.

Title:

Nuclear Plant Interface Coordination

2.

Number:

NUC-001-43

3.

Purpose: This standard requires coordination between Nuclear Plant Generator
Operators and Transmission Entities for the purpose of ensuring nuclear plant safe
operation and shutdown.

4.

Applicability:
4.1. Functional Entities:
4.1.1

Nuclear Plant Generator Operators.

4.2. Transmission Entities shall mean all entities that are responsible for providing
services related to Nuclear Plant Interface Requirements (NPIRs). Such entities
may include one or more of the following:

5.

4.2.1

Transmission Operators.

4.2.2

Transmission Owners.

4.2.3

Transmission Planners.

4.2.4

Transmission Service Providers.

4.2.5

Balancing Authorities.

4.2.6

Reliability Coordinators.

4.2.7

Planning Coordinators.

4.2.8

Distribution Providers.

4.2.9

Load-Serving Entities.

4.2.104.2.9

Generator Owners.

4.2.114.2.10

Generator Operators.

Effective Date: See Implementation Plan.

Background: Project 2012-13 Nuclear Power Interface Coordination seeks to implement
the changes that were proposed by the NUC FYRT. The NUC FYRT was appointed by the
Standards Committee Executive Committee on April 22, 2013. The NUC FYRT reviewed
the NUC-001-2.1 standard to identify opportunities for consolidation and additional
improvements. The NUC FYRT posted its recommendation to revise NUC-001-2.1 for
industry comment on July 27, 2013. The NUC FYRT considered comments and submitted its
final recommendation to revise NUC-001-2.1, along with a Standards Authorization Request
(SAR) to the Standards Committee on October 17, 2013. The Standards Committee accepted

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NUC-001-34— Nuclear Plant Interface Coordination

the recommendation of the FYRT and appointed the team as the Standard Drafting Team
(SDT) to implement the recommendation.
5.

Effective Dates: First day of the first calendar quarter that is twelve months beyond
the date that this standard is approved by applicable regulatory authorities, 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 that is twelve months after the date this standard is
adopted by the NERC Board of Trustees or as otherwise provided for in that
jurisdiction.

B. Requirements and Measures
R1. The Nuclear Plant Generator Operator shall provide the proposed NPIRs in writing to
the applicable Transmission Entities and shall verify receipt. [Violation Risk Factor:
Medium] [Time Horizon: Long-term Planning ]
M1. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, provide a copy of the transmittal and receipt of transmittal of
the proposed NPIRs to the responsible Transmission Entities.
R2. The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
have in effect one or more Agreements 1 that include mutually agreed to NPIRs and
document how the Nuclear Plant Generator Operator and the applicable Transmission
Entities shall address and implement these NPIRs. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning ]
M2. The Nuclear Plant Generator Operator and each Transmission Entity shall each have a
copy of the currently effective Agreement(s) which document how the Nuclear Plant
Generator Operator and the applicable Transmission Entities address and implement
the NPIRs available for inspection upon request of the Compliance Enforcement
Authority.
R3. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall incorporate the NPIRs into their planning analyses of the
electric system and shall communicate the results of these analyses to the Nuclear Plant
Generator Operator.: [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning ]
M3. Each Transmission Entity responsible for planning analyses in accordance with the
Agreement shall, upon request of the Compliance Enforcement Authority, provide a
copy of the planning analyses results transmitted to the Nuclear Plant Generator
Operator, showing incorporation of the NPIRs. The Compliance Enforcement
1

Agreements may include mutually agreed upon procedures or protocols in effect between entities or between
departments of a vertically integrated system.

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NUC-001-34— Nuclear Plant Interface Coordination

Authority shall refer to the Agreements developed in accordance with this standard for
specific requirements.
R4. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall [Violation Risk Factor: High] [Time Horizon: Operations
Planning and Real-time Operations]
4.1. Incorporate the NPIRs into their operating analyses of the electric system.
4.2. Operate the electric system to meet the NPIRs.
4.3. Inform the Nuclear Plant Generator Operator when the ability to assess the
operation of the electric system affecting NPIRs is lost.
M4. Each Transmission Entity responsible for operating the electric system in accordance
with the Agreement shall demonstrate or provide evidence of the following, upon
request of the Compliance Enforcement Authority:
•

The NPIRs have been incorporated into the current operating analysis of the
electric system. (Requirement 4.1)

•

The electric system was operated to meet the NPIRs. (Requirement 4.2)

•

The Transmission Entity informed the Nuclear Plant Generator Operator when
it became aware it lost the capability to assess the operation of the electric
system affecting the NPIRs

R5. Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall operate the nuclear plant to meet the NPIRs. [Violation Risk
Factor: High] [Time Horizon: Operations Planning and Real-time Operations ]
M5. The Nuclear Plant Generator Operator shall, upon request of the Compliance
Enforcement Authority, demonstrate or provide evidence that the nuclear power plant
is being operated consistent with the NPIRs.
R6. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities and the Nuclear Plant Generator Operator shall coordinate
outages and maintenance activities which affect the NPIRs. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]
M6. The Transmission Entities and Nuclear Plant Generator Operator shall, upon request of
the Compliance Enforcement Authority, provide evidence of the coordination between
the Transmission Entities and the Nuclear Plant Generator Operator regarding outages
and maintenance activities which affect the NPIRs.
R7. Per the Agreements developed in accordance with this standard, the Nuclear Plant
Generator Operator shall inform the applicable Transmission Entities of actual or
proposed changes to nuclear plant design (e.g., protective relay setpoints),

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NUC-001-34— Nuclear Plant Interface Coordination

configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
M7. The Nuclear Plant Generator Operator shall provide evidence that it informed the
applicable Transmission Entities of changes to nuclear plant design (e.g., protective
relay setpoints), configuration, operations, limits, or capabilities that may impact the
ability of the Transmission Entities to meet the NPIRs.
R8. Per the Agreements developed in accordance with this standard, the applicable
Transmission Entities shall inform the Nuclear Plant Generator Operator of actual or
proposed changes to electric system design (e.g., protective relay setpoints),
configuration, operations, limits, or capabilities that may impact the ability of the
electric system to meet the NPIRs. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning]
M8. The Transmission Entities shall each provide evidence that the entities informed the
Nuclear Plant Generator Operator of changes to electric system design (e.g., protective
relay setpoints), configuration, operations, limits, or capabilities that may impact the
ability of the Nuclear Plant Generator Operator to meet the NPIRs.
R9. The Nuclear Plant Generator Operator and the applicable Transmission Entities shall
include the following elements in aggregate within the Agreement(s) identified in R2.
•

Where multiple Agreements with a single Transmission Entity are put into
effect, the R9 elements must be addressed in aggregate within the
Agreements; however, each Agreement does not have to contain each
element. The Nuclear Plant Generator Operator and the Transmission Entity
are responsible for ensuring all the R9 elements are addressed in aggregate
within the Agreements.

•

Where Agreements with multiple Transmission Entities are required, the
Nuclear Plant Generator Operator is responsible for ensuring all the R9
elements are addressed in aggregate within the Agreements with the
Transmission Entities. The Agreements with each Transmission Entity do not
have to contain each element; however, the Agreements with the multiple
Transmission Entities, in the aggregate, must address all R9 elements. For
each Agreement(s), the Nuclear Plant Generator Operator and the
Transmission Entity are responsible to ensure the Agreement(s) contain(s) the
elements of R9 applicable to that Transmission Entity. : [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]

9.1. Retired. [Note: Part 9.1 was retired under the Paragraph 81 project. The NUC
SDT proposes to leave this Part blank to avoid renumbering Requirement parts
that would impact existing agreements throughout the industry.]

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NUC-001-34— Nuclear Plant Interface Coordination

9.2. Technical requirements and analysis:
9.2.1. Identification of parameters, limits, configurations, and operating
scenarios included in the NPIRs and, as applicable, procedures for
providing any specific data not provided within the Agreement.
9.2.2. Identification of facilities, components, and configuration restrictions that
are essential for meeting the NPIRs.
9.2.3. Types of planning and operational analyses performed specifically to
support the NPIRs, including the frequency of studies and types of
Contingencies and scenarios required.
9.3. Operations and maintenance coordination
9.3.1. Designation of ownership of electrical facilities at the interface between
the electric system and the nuclear plant and responsibilities for
operational control coordination and maintenance of these facilities.
9.3.2. Identification of any maintenance requirements for equipment not owned
or controlled by the Nuclear Plant Generator Operator that are necessary
to meet the NPIRs.
9.3.3. Coordination of testing, calibration and maintenance of on-site and off-site
power supply systems and related components.
9.3.4. Provisions to address mitigating actions needed to avoid violating NPIRs
and to address periods when responsible Transmission Entity loses the
ability to assess the capability of the electric system to meet the NPIRs.
These provisions shall include responsibility to notify the Nuclear Plant
Generator Operator within a specified time frame.
9.3.5. Provision for considering, within the restoration process, the requirements
and urgency of a nuclear plant that has lost all off-site and on-site AC
power.
9.3.6. Coordination of physical and cyber security protection at the nuclear plant
interface to ensure each asset is covered under at least one entity’s plan.
9.3.7. Coordination of the NPIRs with transmission system Remedial Action
Schemes and any programs that reduce or shed load based on
underfrequency or undervoltage.
9.4. Communications and training Administrative elements:
9.4.1. Provisions for communications affecting the NPIRs between the Nuclear
Plant Generator Operator and Transmission Entities, including
communications protocols, notification time requirements, and definitions
of applicable unique terms.
9.4.2. Provisions for coordination during an off-normal or emergency event
affecting the NPIRs, including the need to provide timely information
explaining the event, an estimate of when the system will be returned to a
normal state, and the actual time the system is returned to normal.

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NUC-001-34— Nuclear Plant Interface Coordination

9.4.3. Provisions for coordinating investigations of causes of unplanned events
affecting the NPIRs and developing solutions to minimize future risk of
such events.
9.4.4. Provisions for supplying information necessary to report to government
agencies, as related to NPIRs.
9.4.5. Provisions for personnel training, as related to NPIRs.
M9. The Nuclear Plant Generator Operator shall have a copy of the Agreement(s) addressing
the elements in Requirement 9 available for inspection upon request of the Compliance
Enforcement Authority. Each Transmission Entity shall have a copy of the Agreement(s)
addressing the elements in Requirement 9 for which it is responsible available for inspection
upon request of the Compliance Enforcement Authority.

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints Text
1.3. Data Retention
The Responsible Entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
•

For Measure 1, the Nuclear Plant Generator Operator shall keep its latest
transmittals and receipts.

•

For Measure 2, the Nuclear Plant Generator Operator and each
Transmission Entity shall have its current, in-force Agreement.

•

For Measure 3, the Transmission Entity shall have the latest planning
analysis results.

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NUC-001-34— Nuclear Plant Interface Coordination

•

For Measures 4, 6 and 8, the Transmission Entity shall keep evidence for
two years plus current.

•

For Measures 5, 6 and 7, the Nuclear Plant Generator Operator shall keep
evidence for two years plus current.

If a Responsible Entity is found non-compliant it shall keep information related to
the noncompliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None

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NUC-001-34— Nuclear Plant Interface Coordination

Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

R1

Medium The Nuclear Plant
Generator Operator
provided the NPIRs to the
applicable entities but did
not verify receipt.

Moderate VSL

High VSL

Severe VSL

The Nuclear Plant
Generator Operator did not
provide the proposed NPIR
to one of the applicable
entities unless there was
only one entity.

The Nuclear Plant
Generator Operator did not
provide the proposed
NPIRs to two of the
applicable entities unless
there were only two
entities.

The Nuclear Plant
Generator Operator did not
provide the proposed
NPIRs to more than two of
applicable entities.
OR
For a particular nuclear
power plant, if the number
of possible applicable
transmission entities is
equal to the number of
applicable transmission
entities not provided NPIRs

R2

Medium N/A

N/A

N/A

The Nuclear Plant
Generator Operator or the
applicable Transmission
Entity does not have in
effect one or more
agreements that include
mutually agreed to NPIRs
and document the
implementation of the
NPIRs.

R3

Medium N/A

The responsible entity
incorporated the NPIRs
into its planning analyses
but did not communicate

N/A

The responsible entity did
not incorporate the NPIRs
into its planning analyses of
the electric system.

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NUC-001-34— Nuclear Plant Interface Coordination
the results to the Nuclear
Plant Generator Operator.

R4

High

N/A

The responsible entity did
not comply with
Requirement R4, Part 4.3.

The responsible entity did
not comply with
Requirement R4, Part R4.1.

The responsible entity did
not comply with
Requirement R4, Part R4.2.

R5

High

N/A

N/A

N/A

The Nuclear Plant
Generator Operator failed
to operate per the NPIRs
developed in accordance
with this standard.

R6

Medium N/A

The Nuclear Plant
Generator Operator or
Transmission Entity failed
to provide outage or
maintenance schedules to
the appropriate parties as
described in the agreement
or on a time period
consistent with the
agreements.

The Nuclear Plant
Generator Operator or
Transmission Entity failed
to coordinate one or more
outages or maintenance
activities in accordance the
requirements of the
agreements.

N/A

R7

High

The Nuclear Plant
Generator Operator did not
inform the applicable
Transmission Entities of
proposed changes to
nuclear plant design (e.g.
protective relay setpoints),
configuration, operations,
limits, or capabilities that
may impact the ability of
the electric system to meet
the NPIRs.

N/A

The Nuclear Plant
Generator Operator did not
inform the applicable
Transmission Entities of
actual changes to nuclear
plant design (e.g. protective
relay setpoints),
configuration, operations,
limits, or capabilities that
may impact the ability of
the electric system to meet
the NPIRs.

The Nuclear Plant
Generator Operator did not
inform the applicable
Transmission Entities of
actual changes to nuclear
plant design (e.g.,
protective relay setpoints),
configuration, operations,
limits or capabilities that
directly impact the ability
of the electric system to
meet the NPIRs.

R8

High

The applicable
Transmission Entities did
not inform the Nuclear

N/A

The applicable
Transmission Entities did
not inform the Nuclear

The applicable
Transmission Entities did
not inform the Nuclear

Page 9 of 13

NUC-001-34— Nuclear Plant Interface Coordination
Plant Generator Operator of
proposed changes to
transmission system design,
configuration (e.g.
protective relay setpoints),
operations, limits, or
capabilities that may
impact the ability of the
electric system to meet the
NPIRs.

R9

Medium

The Agreement(s)
identified in R2. between
the Nuclear Plant Generator
Operator and the applicable
Transmission Entity failed
to include up to 20% of the
combined sub-components
in Requirement R9 Parts
9.2, 9.3 and 9.4 applicable
to that entity.

Plant Generator Operator of
actual changes to
transmission system design
(e.g. protective relay
setpoints), configuration,
operations, limits, or
capabilities that may
impact the ability of the
electric system to meet the
NPIRs.

Plant Generator Operator of
actual changes to
transmission system design
(e.g. protective relay
setpoints), configuration,
operations, limits, or
capabilities that directly
impacts the ability of the
electric system to meet the
NPIRs.

The Agreement(s)
identified in R2. between
the Nuclear Plant Generator
Operator and the applicable
Transmission Entity failed
to include greater than
20%, but less than 40% of
the combined subcomponents in
Requirement R9 Parts 9.2,
9.3 and 9.4 applicable to
the entity.

The Agreement(s)
identified in R2. between
the Nuclear Plant Generator
Operator and the applicable
Transmission Entity failed
to include 40% or more of
the combined subcomponents in
Requirement R9 Parts 9.2,
9.3 and 9.4 applicable to
the entity.

Page 10 of 13

NUC-001-4— Nuclear Plant Interface Coordination

D. Regional Variances
The design basis for Canadian (CANDU) nuclear power plants (NPPs) does not result in the
same licensing requirements as U.S. NPPs. Nuclear Regulatory Commission (NRC) design
criteria specifies that in addition to emergency on-site electrical power, electrical power from
the electric network also be provided to permit safe shutdown. There are no equivalent
Canadian Regulatory requirements for electrical power from the electric network to be
provided to permit safe shutdown. Therefore the definition of Nuclear Plant Licensing
Requirements (NPLR) for Canadian CANDU NPPs will be as follows:
Canadian Nuclear Plant Licensing Requirements (CNPLR) are requirements included in the
design basis of the nuclear plant and are statutorily mandated for the operation of the plant;
when used in this standard, NPLR shall mean nuclear power plant licensing requirements for
avoiding preventable challenges to nuclear safety as a result of an electric system
disturbance, transient, or condition.
E. Interpretations
None.
F. Associated Documents
None

Version History

Page 11 of 13

NUC-001-4— Nuclear Plant Interface Coordination

Version

Date

Action

Change Tracking

1

May 2, 2007

Approved by Board of Trustees

New

2

August 5, 2009

Adopted by Board of Trustees

Revised. Modifications for
Order 716 to Requirement
R9.3.5 and footnote 1;
modifications to bring
compliance elements into
conformance with the
latest version of the ERO
Rules of Procedure.

2

January 22, 2010

Approved by FERC on January 21,
2010. Added Effective Date

Update

2

February 7, 2013

R9.1, R9.1.1, R9.1.2, R9.1.3, and
R9.1.4 and associated elements
approved by NERC Board of
Trustees for retirement as part of the
Paragraph 81 project (Project 201302) pending applicable regulatory
approval.

2

November 21,
2013

2.1

April 11, 2012

2.1

September 9,
2013

3

March 2014

R9.1, R9.1.1, R9.1.2, R9.1.3, and
R9.1.4 and associated elements
approved by FERC for retirement as
part of the Paragraph 81 project
(Project 2013-02)
Errata approved by the Standards
Committee; (Capitalized “Protection
System” in accordance with
Implementation Plan for Project
2007-17 approval of revised
definition of “Protection System”)
Informational filing submitted to
reflect the revised definition of
Protection System in accordance
with the Implementation Plan for the
revised term.
Modifications to implement the
recommendations of the five-year
review of NUC-001, which was
accepted by the Standards
Committee on October 17, 2013.

3

August 14, 2014

Adopted by the NERC Board of
Trustees

3

November 4,
2014

FERC letter order issued approving
NUC-001-3

Errata associated with
Project 2007-17

Revision

Page 12 of 13

NUC-001-4— Nuclear Plant Interface Coordination

4

Adopted by the NERC Board of
Trustees

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 R5:
The NUC FYRT recommended R5 be revised for consistency with R4 and to clarify that nuclear
plants must be operated to meet the Nuclear Plant Interface Requirements.
Rationale for R7 and R8:
The NUC FYRT recommended deleting “Protection Systems” in Requirements R7 and R8 since
it is a subset of the "nuclear plant design" and "electric system design" elements currently
contained in R7 and R8 respectively; and adding a parenthetical clause (e.g. protective setpoints)
to R7 following "nuclear plant design" and parenthetical clause (e.g. relay setpoints) to R8
following "electric system design."

Rationale for R9:
The NUC FYRT recommended that R9 be revised to clarify that all agreements do not have to
discuss each of the elements in R9, but that the sum total of the agreements need to address the
elements. In addition, for clarity in Part 9.4.1, the NUC FYRT recommended that "affecting the
NPIRs" be inserted following "Provisions for communications" and "applicable unique" be
inserted following ""definitions of."
Rationale for R9.3.7:
The term “Special Protection Systems” (SPS) was replaced with “Remedial Action Schemes”
(RAS) in order to align with other current NERC standards development work in Project 201005.2: Special Protection Systems. Project 2010-05.2 has proposed to replace SPS with RAS
throughout all of the NERC Standards in order to move to the use of a single term. RAS and SPS
have the same definition in the NERC Glossary of Terms.

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PRC-006-4 — Automatic Underfrequency Load Shedding

A. Introduction
1.
Title:
Automatic Underfrequency Load Shedding
2.

Number:

3.

Purpose: To establish design and documentation requirements for automatic
underfrequency load shedding (UFLS) programs to arrest declining frequency, assist
recovery of frequency following underfrequency events and provide last resort
system preservation measures.

4.

Applicability:

PRC-006-4

4.1. Planning Coordinators
4.2. UFLS entities shall mean all entities that are responsible for the ownership,
operation, or control of UFLS equipment as required by the UFLS program
established by the Planning Coordinators. Such entities may include one or
more of the following:
4.2.1 Transmission Owners
4.2.2 Distribution Providers
4.2.3 UFLS-Only Distribution Providers
4.3. Transmission Owners that own Elements identified in the UFLS program
established by the Planning Coordinators.
5.

Effective Date:
See Implementation Plan

B. Requirements and Measures
R1.

Each Planning Coordinator shall develop and document criteria, including
consideration of historical events and system studies, to select portions of the Bulk
Electric System (BES), including interconnected portions of the BES in adjacent
Planning Coordinator areas and Regional Entity areas that may form islands. [VRF:
Medium][Time Horizon: Long-term Planning]

M1. Each Planning Coordinator shall have evidence such as reports, or other documentation
of its criteria to select portions of the Bulk Electric System that may form islands
including how system studies and historical events were considered to develop the
criteria per Requirement R1.
R2.

Each Planning Coordinator shall identify one or more islands to serve as a basis for
designing its UFLS program including: [VRF: Medium][Time Horizon: Long-term
Planning]
2.1. Those islands selected by applying the criteria in Requirement R1, and

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PRC-006-4 — Automatic Underfrequency Load Shedding

2.2. Any portions of the BES designed to detach from the Interconnection (planned
islands) as a result of the operation of a relay scheme or Special Protection
System, and
2.3. A single island that includes all portions of the BES in either the Regional Entity
area or the Interconnection in which the Planning Coordinator’s area resides. If a
Planning Coordinator’s area resides in multiple Regional Entity areas, each of
those Regional Entity areas shall be identified as an island. Planning Coordinators
may adjust island boundaries to differ from Regional Entity area boundaries by
mutual consent where necessary for the sole purpose of producing contiguous
regional islands more suitable for simulation.
M2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s) as a basis
for designing a UFLS program that meet the criteria in Requirement R2, Parts 2.1
through 2.3.
R3.

Each Planning Coordinator shall develop a UFLS program, including notification of and
a schedule for implementation by UFLS entities within its area, that meets the
following performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s). [VRF:
High][Time Horizon: Long-term Planning]
3.1. Frequency shall remain above the Underfrequency Performance Characteristic
curve in PRC-006-4 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
3.2. Frequency shall remain below the Overfrequency Performance Characteristic
curve in PRC-006-4 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
3.3. Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two seconds
cumulatively per simulated event, and shall not exceed 1.10 per unit for longer
than 45 seconds cumulatively per simulated event at each generator bus and
generator step-up transformer high-side bus associated with each of the
following:
• Individual generating units greater than 20 MVA (gross nameplate rating)
directly connected to the BES
• Generating plants/facilities greater than 75 MVA (gross aggregate nameplate
rating) directly connected to the BES
• Facilities consisting of one or more units connected to the BES at a common
bus with total generation above 75 MVA gross nameplate rating.

M3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its UFLS program, including the
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PRC-006-4 — Automatic Underfrequency Load Shedding

notification of the UFLS entities of implementation schedule, that meet the criteria in
Requirement R3, Parts 3.1 through 3.3.
R4.

Each Planning Coordinator shall conduct and document a UFLS design assessment at
least once every five years that determines through dynamic simulation whether the
UFLS program design meets the performance characteristics in Requirement R3 for
each island identified in Requirement R2. The simulation shall model each of the
following: [VRF: High][Time Horizon: Long-term Planning]
4.1. Underfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip above the
Generator Underfrequency Trip Modeling curve in PRC-006-4 - Attachment 1.
4.2. Underfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip above
the Generator Underfrequency Trip Modeling curve in PRC-006-4 - Attachment 1.
4.3. Underfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-4 - Attachment 1.
4.4. Overfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-4 — Attachment 1.
4.5. Overfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip below
the Generator Overfrequency Trip Modeling curve in PRC-006-4 — Attachment 1.
4.6. Overfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-4 — Attachment 1.
4.7. Any automatic Load restoration that impacts frequency stabilization and operates
within the duration of the simulations run for the assessment.

M4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its UFLS design
assessment that demonstrates it meets Requirement R4, Parts 4.1 through 4.7.
R5.

Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall coordinate its UFLS program design
with all other Planning Coordinators whose areas or portions of whose areas are also
part of the same identified island through one of the following: [VRF: High][Time
Horizon: Long-term Planning]

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PRC-006-4 — Automatic Underfrequency Load Shedding
•

Develop a common UFLS program design and schedule for implementation per
Requirement R3 among the Planning Coordinators whose areas or portions of
whose areas are part of the same identified island, or

•

Conduct a joint UFLS design assessment per Requirement R4 among the Planning
Coordinators whose areas or portions of whose areas are part of the same
identified island, or

•

Conduct an independent UFLS design assessment per Requirement R4 for the
identified island, and in the event the UFLS design assessment fails to meet
Requirement R3, identify modifications to the UFLS program(s) to meet
Requirement R3 and report these modifications as recommendations to the other
Planning Coordinators whose areas or portions of whose areas are also part of
the same identified island and the ERO.

M5. Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall have dated evidence such as joint
UFLS program design documents, reports describing a joint UFLS design assessment,
letters that include recommendations, or other dated documentation demonstrating
that it coordinated its UFLS program design with all other Planning Coordinators whose
areas or portions of whose areas are also part of the same identified island per
Requirement R5.
R6.

Each Planning Coordinator shall maintain a UFLS database containing data necessary to
model its UFLS program for use in event analyses and assessments of the UFLS
program at least once each calendar year, with no more than 15 months between
maintenance activities. [VRF: Lower][Time Horizon: Long-term Planning]

M6. Each Planning Coordinator shall have dated evidence such as a UFLS database, data
requests, data input forms, or other dated documentation to show that it maintained a
UFLS database for use in event analyses and assessments of the UFLS program per
Requirement R6 at least once each calendar year, with no more than 15 months
between maintenance activities.
R7.

Each Planning Coordinator shall provide its UFLS database containing data necessary to
model its UFLS program to other Planning Coordinators within its Interconnection
within 30 calendar days of a request. [VRF: Lower][Time Horizon: Long-term Planning]

M7. Each Planning Coordinator shall have dated evidence such as letters, memorandums,
e-mails or other dated documentation that it provided their UFLS database to other
Planning Coordinators within their Interconnection within 30 calendar days of a
request per Requirement R7.
R8.

Each UFLS entity shall provide data to its Planning Coordinator(s) according to the
format and schedule specified by the Planning Coordinator(s) to support maintenance
of each Planning Coordinator’s UFLS database. [VRF: Lower][Time Horizon: Long-term
Planning]

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PRC-006-4 — Automatic Underfrequency Load Shedding

M8. Each UFLS Entity shall have dated evidence such as responses to data requests,
spreadsheets, letters or other dated documentation that it provided data to its
Planning Coordinator according to the format and schedule specified by the Planning
Coordinator to support maintenance of the UFLS database per Requirement R8.
R9.

Each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
as determined by its Planning Coordinator(s) in each Planning Coordinator area in
which it owns assets. [VRF: High][Time Horizon: Long-term Planning]

M9. Each UFLS Entity shall have dated evidence such as spreadsheets summarizing feeder
load armed with UFLS relays, spreadsheets with UFLS relay settings, or other dated
documentation that it provided automatic tripping of load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
per Requirement R9.
R10. Each Transmission Owner shall provide automatic switching of its existing capacitor
banks, Transmission Lines, and reactors to control over-voltage as a result of
underfrequency load shedding if required by the UFLS program and schedule for
implementation, including any Corrective Action Plan, as determined by the Planning
Coordinator(s) in each Planning Coordinator area in which the Transmission Owner
owns transmission. [VRF: High][Time Horizon: Long-term Planning]
M10. Each Transmission Owner shall have dated evidence such as relay settings, tripping
logic or other dated documentation that it provided automatic switching of its existing
capacitor banks, Transmission Lines, and reactors in order to control over-voltage as a
result of underfrequency load shedding if required by the UFLS program and schedule
for implementation, including any Corrective Action Plan, per Requirement R10.
R11. Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
conduct and document an assessment of the event within one year of event actuation
to evaluate: [VRF: Medium][Time Horizon: Operations Assessment]
11.1. The performance of the UFLS equipment,
11.2. The effectiveness of the UFLS program.
M11. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted an
event assessment of the performance of the UFLS equipment and the effectiveness of
the UFLS program per Requirement R11.
R12. Each Planning Coordinator, in whose islanding event assessment (per R11) UFLS
program deficiencies are identified, shall conduct and document a UFLS design
assessment to consider the identified deficiencies within two years of event actuation.
[VRF: Medium][Time Horizon: Operations Assessment]

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PRC-006-4 — Automatic Underfrequency Load Shedding

M12. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted a
UFLS design assessment per Requirements R12 and R4 if UFLS program deficiencies are
identified in R11.
R13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall coordinate its event assessment (in accordance
with Requirement R11) with all other Planning Coordinators whose areas or portions of
whose areas were also included in the same islanding event through one of the
following: [VRF: Medium][Time Horizon: Operations Assessment]
•

Conduct a joint event assessment per Requirement R11 among the Planning
Coordinators whose areas or portions of whose areas were included in the same
islanding event, or

•

Conduct an independent event assessment per Requirement R11 that reaches
conclusions and recommendations consistent with those of the event
assessments of the other Planning Coordinators whose areas or portions of
whose areas were included in the same islanding event, or

•

Conduct an independent event assessment per Requirement R11 and where the
assessment fails to reach conclusions and recommendations consistent with
those of the event assessments of the other Planning Coordinators whose areas
or portions of whose areas were included in the same islanding event, identify
differences in the assessments that likely resulted in the differences in the
conclusions and recommendations and report these differences to the other
Planning Coordinators whose areas or portions of whose areas were included in
the same islanding event and the ERO.

M13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall have dated evidence such as a joint assessment
report, independent assessment reports and letters describing likely reasons for
differences in conclusions and recommendations, or other dated documentation
demonstrating it coordinated its event assessment (per Requirement R11) with all
other Planning Coordinator(s) whose areas or portions of whose areas were also
included in the same islanding event per Requirement R13.
R14. Each Planning Coordinator shall respond to written comments submitted by UFLS
entities and Transmission Owners within its Planning Coordinator area following a
comment period and before finalizing its UFLS program, indicating in the written
response to comments whether changes will be made or reasons why changes will not
be made to the following [VRF: Lower][Time Horizon: Long-term Planning]:
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PRC-006-4 — Automatic Underfrequency Load Shedding

14.1. UFLS program, including a schedule for implementation
14.2. UFLS design assessment
14.3. Format and schedule of UFLS data submittal
M14. Each Planning Coordinator shall have dated evidence of responses, such as e-mails and
letters, to written comments submitted by UFLS entities and Transmission Owners
within its Planning Coordinator area following a comment period and before finalizing
its UFLS program per Requirement R14.
R15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall develop a Corrective Action Plan
and a schedule for implementation by the UFLS entities within its area. [VRF:
High][Time Horizon: Long-term Planning]
15.1. For UFLS design assessments performed under Requirement R4 or R5, the
Corrective Action Plan shall be developed within the five-year time frame
identified in Requirement R4.
15.2. For UFLS design assessments performed under Requirement R12, the Corrective
Action Plan shall be developed within the two-year time frame identified in
Requirement R12.
M15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall have a dated Corrective Action
Plan and a schedule for implementation by the UFLS entities within its area, that was
developed within the time frame identified in Part 15.1 or 15.2.

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PRC-006-4 — Automatic Underfrequency Load Shedding

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
Each Planning Coordinator and UFLS entity shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
•

Each Planning Coordinator shall retain the current evidence of Requirements
R1, R2, R3, R4, R5, R12, R14, and R15, Measures M1, M2, M3, M4, M5, M12,
M14, and M15 as well as any evidence necessary to show compliance since
the last compliance audit.

•

Each Planning Coordinator shall retain the current evidence of UFLS database
update in accordance with Requirement R6, Measure M6, and evidence of the
prior year’s UFLS database update.

•

Each Planning Coordinator shall retain evidence of any UFLS database
transmittal to another Planning Coordinator since the last compliance audit in
accordance with Requirement R7, Measure M7.

•

Each UFLS entity shall retain evidence of UFLS data transmittal to the Planning
Coordinator(s) since the last compliance audit in accordance with
Requirement R8, Measure M8.

•

Each UFLS entity shall retain the current evidence of adherence with the UFLS
program in accordance with Requirement R9, Measure M9, and evidence of
adherence since the last compliance audit.

•

Transmission Owner shall retain the current evidence of adherence with the
UFLS program in accordance with Requirement R10, Measure M10, and
evidence of adherence since the last compliance audit.

•

Each Planning Coordinator shall retain evidence of Requirements R11, and
R13, and Measures M11, and M13 for 6 calendar years.

If a Planning Coordinator or UFLS entity is found non-compliant, it shall keep
information related to the non-compliance until found compliant or for the
retention period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
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PRC-006-4 — Automatic Underfrequency Load Shedding

1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaints
1.4. Additional Compliance Information
None

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PRC-006-4 — Automatic Underfrequency Load Shedding

Violation Severity Levels
R#
R1

Lower VSL
N/A

Moderate VSL

High VSL

Severe VSL

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas that may
form islands.

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events and system studies, to
select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas
and Regional Entity areas, that
may form islands.

The Planning Coordinator failed
to develop and document
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas and
Regional Entity areas, that may
form islands.

The Planning Coordinator
identified an island(s) to serve

The Planning Coordinator
identified an island(s) to serve

OR
The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of system
studies, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas, that
may form islands.
R2

N/A
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The Planning Coordinator
identified an island(s) to

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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

serve as a basis for designing
its UFLS program but failed to
include one (1) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its
UFLS program but failed to
include two (2) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its UFLS
program but failed to include all
of the Parts as specified in
Requirement R2, Parts 2.1, 2.2,
or 2.3.
OR
The Planning Coordinator failed
to identify any island(s) to serve
as a basis for designing its UFLS
program.

R3

N/A

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation
by UFLS entities within its
area where imbalance = [(load
— actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet one (1) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of
underfrequency conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation
by UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet two (2) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of underfrequency
conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified
island(s).,but failed to meet all
the performance characteristic
in Requirement R3, Parts 3.1,
3.2, and 3.3 in simulations of
underfrequency conditions.
OR
The Planning Coordinator failed
to develop a UFLS program

Draft 2 of PRC-006-4
January 2020

Page 11 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
including notification of and a
schedule for implementation by
UFLS entities within its area

R4

The Planning Coordinator
conducted and documented a
UFLS assessment at least
once every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics
in Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
one (1) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

Draft 2 of PRC-006-4
January 2020

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
two (2) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
three (3) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

Page 12 of 40

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
R3 but simulation failed to
include four (4) or more of the
items as specified in
Requirement R4, Parts 4.1
through 4.7.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
R3 for each island identified in
Requirement R2

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R5

N/A

N/A

N/A

The Planning Coordinator, whose
area or portions of whose area is
part of an island identified by it
or another Planning Coordinator
which includes multiple Planning
Coordinator areas or portions of
those areas, failed to coordinate
its UFLS program design through
one of the manners described in
Requirement R5.

R6

N/A

N/A

N/A

The Planning Coordinator failed
to maintain a UFLS database for
use in event analyses and
assessments of the UFLS
program at least once each
calendar year, with no more
than 15 months between
maintenance activities.

R7

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 30 calendar days
and up to and including 40
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 40 calendar days
but less than and including 50
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 50 calendar days
but less than and including 60
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 60 calendar days
following the request.

Draft 2 of PRC-006-4
January 2020

Page 13 of 40

OR

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator failed
to provide its UFLS database to
other Planning Coordinators.

R8

The UFLS entity provided data
to its Planning Coordinator(s)
less than or equal to 10
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 10 calendar days
but less than or equal to 15
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 15 calendar days
but less than or equal to 20
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data to
its Planning Coordinator(s) more
than 20 calendar days following
the schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided less
than 90% but more than (and
including) 85% of automatic
tripping of Load in accordance
with the UFLS program design

The UFLS entity provided less
than 85% of automatic tripping
of Load in accordance with the
UFLS program design and
schedule for implementation,

OR
The UFLS entity provided data
to its Planning Coordinator(s)
but the data was not
according to the format
specified by the Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.
R9

The UFLS entity provided less
than 100% but more than
(and including) 95% of
automatic tripping of Load in
accordance with the UFLS
Draft 2 of PRC-006-4
January 2020

The UFLS entity provided less
than 95% but more than (and
including) 90% of automatic
tripping of Load in accordance
with the UFLS program design

Page 14 of 40

OR
The UFLS entity failed to provide
data to its Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

program design and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which
it owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

including any Corrective Action
Plan, as determined by the
Planning Coordinator(s) area in
which it owns assets.

R10

The Transmission Owner
provided less than 100% but
more than (and including)
95% automatic switching of
its existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 95% but
more than (and including)
90% automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 90% but
more than (and including) 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the UFLS
program and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission Owner
owns transmission.

The Transmission Owner
provided less than 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and reactors
to control over-voltage if
required by the UFLS program
and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each Planning
Coordinator area in which the
Transmission Owner owns
transmission.

R11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of the

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,

Draft 2 of PRC-006-4
January 2020

Page 15 of 40

Severe VSL

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than one year
but less than or equal to 13
months of actuation.

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than 13 months
but less than or equal to 14
months of actuation.

UFLS program, conducted and
documented an assessment of
the event and evaluated the
parts as specified in
Requirement R11, Parts 11.1
and 11.2 within a time greater
than 14 months but less than
or equal to 15 months of
actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the
initializing set points of the
UFLS program, conducted and
documented an assessment of
the event within one year of
event actuation but failed to
evaluate one (1) of the Parts
as specified in Requirement
R11, Parts11.1 or 11.2.

Draft 2 of PRC-006-4
January 2020

Page 16 of 40

Severe VSL
conducted and documented an
assessment of the event and
evaluated the parts as specified
in Requirement R11, Parts 11.1
and 11.2 within a time greater
than 15 months of actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to conduct and document
an assessment of the event and
evaluate the Parts as specified in
Requirement R11, Parts 11.1 and
11.2.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
conducted and documented an
assessment of the event within
one year of event actuation but
failed to evaluate all of the Parts

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
as specified in Requirement R11,
Parts 11.1 and 11.2.

R12

R13

N/A

N/A

Draft 2 of PRC-006-4
January 2020

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than two
years but less than or equal to
25 months of event actuation.

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than 25
months but less than or equal
to 26 months of event
actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, conducted and documented
a UFLS design assessment to
consider the identified
deficiencies greater than 26
months of event actuation.

N/A

N/A

The Planning Coordinator, in
whose area a BES islanding event
occurred that also included the
area(s) or portions of area(s) of
other Planning Coordinator(s) in
the same islanding event and
that resulted in system
frequency excursions below the
initializing set points of the UFLS
Page 17 of 40

OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, failed to conduct and
document a UFLS design
assessment to consider the
identified deficiencies.

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
program, failed to coordinate its
UFLS event assessment with all
other Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event in
one of the manners described in
Requirement R13

R14

N/A

N/A

N/A

The Planning Coordinator failed
to respond to written comments
submitted by UFLS entities and
Transmission Owners within its
Planning Coordinator area
following a comment period and
before finalizing its UFLS
program, indicating in the
written response to comments
whether changes were made or
reasons why changes were not
made to the items in Parts 14.1
through 14.3.

R15

N/A

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance

Draft 2 of PRC-006-4
January 2020

Page 18 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Draft 2 of PRC-006-4
January 2020

Moderate VSL

High VSL

Severe VSL

characteristics in Requirement
R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period of
up to 1 month.

characteristics in Requirement
R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period
greater than 1 month but not
more than 2 months.

characteristics in Requirement
R3, but failed to develop a
Corrective Action Plan and a
schedule for implementation by
the UFLS entities within its area.

Page 19 of 40

OR
The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance
characteristics in Requirement
R3, and developed a Corrective
Action Plan and a schedule for
implementation by the UFLS
entities within its area, but
exceeded the permissible time
frame for development by a
period greater than 2 months.

PRC-006-4 — Automatic Underfrequency Load Shedding

D. Regional Variances
D.A. Regional Variance for the Quebec Interconnection
The following Interconnection-wide variance shall be applicable in the Quebec
Interconnection and replaces, in their entirety, Requirements R3 and R4 and the
violation severity levels associated with Requirements R3 and R4.
Rationale for Requirement D.A.3:
There are two modifications for requirement D.A.3 :
1. 25% Generation Deficiency : Since the Quebec Interconnection has no potential
viable BES Island in underfrequency conditions, the largest generation deficiency
scenarios are limited to extreme contingencies not already covered by RAS.
Based on Hydro-Québec TransÉnergie Transmission Planning requirements, the
stability of the network shall be maintained for extreme contingencies using a case
representing internal transfers not expected to be exceeded 25% of the time.
The Hydro-Québec TransÉnergie defense plan to cover these extreme contingencies
includes two RAS (RPTC- generation rejection and remote load shedding and TDST a centralized UVLS) and the UFLS.
2. Frequency performance curve (attachment 1A) : Specific cases where a small
generation deficiency using a peak case scenario with the minimum requirement of
spinning reserve can lead to an acceptable frequency deviation in the Quebec
Interconnection while stabilizing between the PRC-006-2 requirement (59.3 Hz) and
the UFLS anti-stall threshold (59.0 Hz).
An increase of the anti-stall threshold to 59.3 Hz would correct this situation but would
cause frequent load shedding of customers without any gain of system reliability.
Therefore, it is preferable to lower the steady state frequency minimum value to 59.0
Hz.
The delay in the performance characteristics curve is harmonized between D.A.3 and
R.3 to 60 seconds.
Rationale for Requirements D.A.3.3. and D.A.4:
The Quebec Interconnection has its own definition of BES. In Quebec, the vast
majority of BES generating plants/facilities are not directly connected to the BES. For
simulations to take into account sufficient generating resources D.A.3.3 and D.A.4
need simply refer to BES generators, plants or facilities since these are listed in a
Registry approved by Québec’s Regulatory Body (Régie de l’Énergie).

D.A.3. Each Planning Coordinator shall develop a UFLS program, including notification
of and a schedule for implementation by UFLS entities within its area, that
meets the following performance characteristics in simulations of
underfrequency conditions resulting from each of these extreme events:
Draft 2 of PRC-006-4
January 2020

Page 20 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

•

Loss of the entire capability of a generating station.

•

Loss of all transmission circuits emanating from a generating station,
switching station, substation or dc terminal.

•

Loss of all transmission circuits on a common right-of-way.

•

Three-phase fault with failure of a circuit breaker to operate and correct
operation of a breaker failure protection system and its associated breakers.

•

Three-phase fault on a circuit breaker, with normal fault clearing.

•

The operation or partial operation of a RAS for an event or condition for
which it was not intended to operate.

[VRF: High][Time Horizon: Long-term Planning]
D.A.3.1.

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-4 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-4 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than
two seconds cumulatively per simulated event, and shall not exceed
1.10 per unit for longer than 45 seconds cumulatively per simulated
event at each Quebec BES generator bus and associated generator
step-up transformer high-side bus

M.D.A.3. Each Planning Coordinator shall have evidence such as reports,
memorandums, e-mails, program plans, or other documentation of its UFLS
program, including the notification of the UFLS entities of implementation
schedule, that meet the criteria in Requirement D.A.3 Parts D.A.3.1 through
D.A.3.3.
D.A.4. Each Planning Coordinator shall conduct and document a UFLS design
assessment at least once every five years that determines through dynamic
simulation whether the UFLS program design meets the performance
characteristics in Requirement D.A.3 for each island identified in Requirement
R2. The simulation shall model each of the following; [VRF: High][Time
Horizon: Long-term Planning]

Draft 2 of PRC-006-4
January 2020

Page 21 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

D.A.4.1

Underfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip above the Generator
Underfrequency Trip Modeling curve in PRC-006-4 - Attachment 1A,
and

D.A.4.2

Overfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip below the Generator
Overfrequency Trip Modeling curve in PRC-006-4 - Attachment 1A,
and

D.A.4.3

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.A.4. Each Planning Coordinator shall have dated evidence such as reports,
dynamic simulation models and results, or other dated documentation of its
UFLS design assessment that demonstrates it meets Requirement D.A.4
Parts D.A.4.1 through D.A.4.3.

Draft 2 of PRC-006-4
January 2020

Page 22 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

D#
DA3

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet two (2) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

Severe VSL
The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Parts D.A.3.1, D.A.3.2, and
D.A.3.3 in simulations of
underfrequency conditions
OR
The Planning Coordinator failed
to develop a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area.

DA4

N/A

Draft 2 of PRC-006-4
January 2020

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed
to include one (1) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include two (2) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include all of the items as

Page 23 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL
specified in Parts D.A.4.1,
D.A.4.2 or D.A.4.3.

High VSL

Severe VSL

specified in Parts D.A.4.1, D.A.4.2
or D.A.4.3.

specified in Parts D.A.4.1, D.A.4.2
and D.A.4.3.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.A.3

Draft 2 of PRC-006-4
January 2020

Page 24 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

D.B.

Regional Variance for the Western Electricity Coordinating Council
The following Interconnection-wide variance shall be applicable in the Western
Electricity Coordinating Council (WECC) and replaces, in their entirety, Requirements R1,
R2, R3, R4, R5, R11, R12, and R13.
D.B.1. Each Planning Coordinator shall participate in a joint regional review with the
other Planning Coordinators in the WECC Regional Entity area that develops and
documents criteria, including consideration of historical events and system
studies, to select portions of the Bulk Electric System (BES) that may form
islands. [VRF: Medium][Time Horizon: Long-term Planning]
M.D.B.1. Each Planning Coordinator shall have evidence such as reports, or other
documentation of its criteria, developed as part of the joint regional review
with other Planning Coordinators in the WECC Regional Entity area to select
portions of the Bulk Electric System that may form islands including how system
studies and historical events were considered to develop the criteria per
Requirement D.B.1.
D.B.2. Each Planning Coordinator shall identify one or more islands from the regional
review (per D.B.1) to serve as a basis for designing a region-wide coordinated
UFLS program including: [VRF: Medium][Time Horizon: Long-term Planning]
D.B.2.1. Those islands selected by applying the criteria in Requirement D.B.1,
and
D.B.2.2. Any portions of the BES designed to detach from the Interconnection
(planned islands) as a result of the operation of a relay scheme or
Special Protection System.
M.D.B.2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s),
from the regional review (per D.B.1), as a basis for designing a region-wide
coordinated UFLS program that meet the criteria in Requirement D.B.2 Parts
D.B.2.1 and D.B.2.2.
D.B.3. Each Planning Coordinator shall adopt a UFLS program, coordinated across the
WECC Regional Entity area, including notification of and a schedule for
implementation by UFLS entities within its area, that meets the following
performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s).
[VRF: High][Time Horizon: Long-term Planning]
D.B.3.1.

Draft 2 of PRC-006-4
January 2020

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-4 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and

Page 25 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

D.B.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-4 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and

D.B.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two
seconds cumulatively per simulated event, and shall not exceed 1.10
per unit for longer than 45 seconds cumulatively per simulated event
at each generator bus and generator step-up transformer high-side
bus associated with each of the following:
D.B.3.3.1. Individual generating units greater than 20 MVA (gross
nameplate rating) directly connected to the BES
D.B.3.3.2. Generating plants/facilities greater than 75 MVA (gross
aggregate nameplate rating) directly connected to the
BES
D.B.3.3.3. Facilities consisting of one or more units connected to
the BES at a common bus with total generation above 75
MVA gross nameplate rating.

M.D.B.3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its adoption of a UFLS
program, coordinated across the WECC Regional Entity area, including the
notification of the UFLS entities of implementation schedule, that meet the
criteria in Requirement D.B.3 Parts D.B.3.1 through D.B.3.3.
D.B.4. Each Planning Coordinator shall participate in and document a coordinated
UFLS design assessment with the other Planning Coordinators in the WECC
Regional Entity area at least once every five years that determines through
dynamic simulation whether the UFLS program design meets the performance
characteristics in Requirement D.B.3 for each island identified in Requirement
D.B.2. The simulation shall model each of the following: [VRF: High][Time
Horizon: Long-term Planning]

Draft 2 of PRC-006-4
January 2020

D.B.4.1.

Underfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip above the Generator Underfrequency Trip Modeling curve
in PRC-006-4 - Attachment 1.

D.B.4.2.

Underfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-4 - Attachment 1.

D.B.4.3.

Underfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
above 75 MVA (gross nameplate rating) that trip above the

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PRC-006-4 — Automatic Underfrequency Load Shedding

Generator Underfrequency Trip Modeling curve in PRC-006-4 Attachment 1.
D.B.4.4.

Overfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip below the Generator Overfrequency Trip Modeling curve in
PRC-006-4 — Attachment 1.

D.B.4.5.

Overfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-4 — Attachment 1.

D.B.4.6.

Overfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
above 75 MVA (gross nameplate rating) that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-4 —
Attachment 1.

D.B.4.7.

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.B.4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its participation
in a coordinated UFLS design assessment with the other Planning Coordinators in
the WECC Regional Entity area that demonstrates it meets Requirement D.B.4
Parts D.B.4.1 through D.B.4.7.
D.B.11.

Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
participate in and document a coordinated event assessment with all affected
Planning Coordinators to conduct and document an assessment of the event
within one year of event actuation to evaluate: [VRF: Medium][Time Horizon:
Operations Assessment]
D.B.11.1. The performance of the UFLS equipment,
D.B.11.2 The effectiveness of the UFLS program

M.D.B.11. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a coordinated event assessment of the performance of the UFLS
equipment and the effectiveness of the UFLS program per Requirement D.B.11.
D.B.12.

Each Planning Coordinator, in whose islanding event assessment (per D.B.11)
UFLS program deficiencies are identified, shall participate in and document a
coordinated UFLS design assessment of the UFLS program with the other

Draft 2 of PRC-006-4
January 2020

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PRC-006-4 — Automatic Underfrequency Load Shedding

Planning Coordinators in the WECC Regional Entity area to consider the
identified deficiencies within two years of event actuation. [VRF: Medium][Time
Horizon: Operations Assessment]
M.D.B.12. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a UFLS design assessment per Requirements D.B.12 and D.B.4 if
UFLS program deficiencies are identified in D.B.11.

Draft 2 of PRC-006-4
January 2020

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#
D.B.1

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical
events, to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical events
and system studies, to select
portions of the BES, including
interconnected portions of the
BES in adjacent Planning
Coordinator areas, that may form
islands

OR

Severe VSL
The Planning Coordinator failed
to participate in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of system studies,
to select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands

Draft 2 of PRC-006-4
January 2020

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#
D.B.2

Lower VSL

Moderate VSL

High VSL

N/A
N/A

The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include one
(1) of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2

Severe VSL
The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include all
of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2
OR
The Planning Coordinator failed
to identify any island(s) from the
regional review to serve as a
basis for designing its UFLS
program.

D.B.3

N/A

Draft 2 of PRC-006-4
January 2020

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, or D.B.3.3 in
simulations of underfrequency
conditions

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that included
notification of and a schedule for
implementation by UFLS entities
within its area, but failed to meet
two (2) of the performance
characteristic in Requirement
D.B.3, Parts D.B.3.1, D.B.3.2, or
D.B.3.3 in simulations of
underfrequency conditions

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, and D.B.3.3 in
simulations of underfrequency
conditions

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
OR
The Planning Coordinator failed
to adopt a UFLS program,
coordinated across the WECC
Regional Entity area, including
notification of and a schedule for
implementation by UFLS entities
within its area.

D.B.4

The Planning Coordinator
participated in and
documented a coordinated
UFLS assessment with the other
Planning Coordinators in the
WECC Regional Entity area at
least once every five years that
determines through dynamic
simulation whether the UFLS
program design meets the
performance characteristics in
Requirement D.B.3 for each
island identified in Requirement
D.B.2 but the simulation failed
to include one (1) of the items
as specified in Requirement
D.B.4, Parts D.B.4.1 through
D.B.4.7.

Draft 2 of PRC-006-4
January 2020

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include two
(2) of the items as specified in
Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include three
(3) of the items as specified in
Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include four
(4) or more of the items as
specified in Requirement D.B.4,
Parts D.B.4.1 through D.B.4.7.
OR

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator failed
to participate in and document a
coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2

D.B.11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below the
initializing set points of the
UFLS program, participated in
and documented a coordinated
event assessment with all
Planning Coordinators whose
areas or portions of whose
areas were also included in the
same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than one year but
Draft 2 of PRC-006-4
January 2020

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 13 months but

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 14 months but

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL
less than or equal to 13 months
of actuation.

Draft 2 of PRC-006-4
January 2020

Moderate VSL
less than or equal to 14 months
of actuation.

High VSL

Severe VSL

less than or equal to 15 months
of actuation.

time greater than 15 months of
actuation.

OR

OR

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event
within one year of event
actuation but failed to evaluate
one (1) of the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 or D.B.11.2.

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to participate in and
document a coordinated event
assessment with all Planning
Coordinators whose areas or
portion of whose areas were also
included in the same island event
and evaluate the parts as
specified in Requirement D.B.11,
Parts D.B.11.1 and D.B.11.2.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
in the same islanding event
within one year of event
actuation but failed to evaluate
all of the parts as specified in
Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2.

D.B.12

N/A

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than two
years but less than or equal to 25
months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 25
months but less than or equal to
26 months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 26
months of event actuation.
OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, failed to participate in
and document a coordinated
UFLS design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area

Draft 2 of PRC-006-4
January 2020

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
to consider the identified
deficiencies

Draft 2 of PRC-006-4
January 2020

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PRC-006-4 — Automatic Underfrequency Load Shedding

E. Associated Documents
Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

May 25, 2010

Completed revision, merging and
updating PRC-006-0, PRC-007-0 and
PRC-009-0.

1

November 4, 2010

Adopted by the Board of Trustees

1

May 7, 2012

FERC Order issued approving PRC006-1 (approval becomes effective
July 10, 2012)

1

November 9, 2012

2

November 13, 2014

FERC Letter Order issued accepting
the modification of the VRF in R5
from (Medium to High) and the
modification of the VSL language in
R8.
Adopted by the Board of Trustees

Revisions made under
Project 2008-02:
Undervoltage Load
Shedding (UVLS) &
Underfrequency Load
Shedding (UFLS) to address
directive issued in FERC
Order No. 763.
Revisions to existing
Requirement R9 and
R10 and addition of
new Requirement
R15.

3

August 10, 2017

4

Draft 2 of PRC-006-4
January 2020

Adopted by the NERC Board of
Trustees
Adopted by the NERC Board of
Trustees

Revisions to the Regional
Variance for the Quebec
Interconnection.

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PRC-006-4 — Automatic Underfrequency Load Shedding

PRC-006-4 – Attachment 1
Underfrequency Load Shedding Program
Design Performance and Modeling Curves for
Requirements R3 Parts 3.1-3.2 and R4 Parts 4.1-4.6
63

Overfrequency Trip Settings
Must Be Modeled for Generators
That Trip Below the Generator
Overfrequency Trip Modeling
Curve

62

Simulated Frequency Must
Remain Between the
Overfrequency and
Underfrequency Performance
Characteristic Curves

60

59

58

Underfrequency Trip Settings
Must Be Modeled for Generators
That Trip Above the Generator
Underfrequency Trip Modeling
Curve

57
0.1

1

Time (sec)

10

100

Generator Overfrequency Trip Modeling (Requirement R4 Parts 4.4-4.6)
Overfrequency Performance Characteristic (Requirement R3 Part 3.2)
Underfrequency Performance Characteristic (Requirement R3 Part 3.1)
Generator Underfrequency Trip Modeling (Requirement R4 Parts 4.1-4.3)

Curve Definitions
Generator Overfrequency Trip Modeling

Overfrequency Performance Characteristic

t≤2s

t>2s

t≤4s

4 s < t ≤ 30 s

t > 30 s

f = 62.2
Hz

f = -0.686log(t) + 62.41
Hz

f = 61.8
Hz

f = -0.686log(t) + 62.21
Hz

f = 60.7
Hz

Draft 2 of PRC-006-4
January 2020

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Frequency (Hz)

61

PRC-006-4 — Automatic Underfrequency Load Shedding

Generator Underfrequency Trip
Modeling

Underfrequency Performance Characteristic

t≤2s

t>2s

t≤2s

2 s < t ≤ 60 s

t > 60 s

f = 57.8
Hz

f = 0.575log(t) + 57.63
Hz

f = 58.0
Hz

f = 0.575log(t) + 57.83
Hz

f = 59.3
Hz

Draft 2 of PRC-006-4
January 2020

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PRC-006-4 — Automatic Underfrequency Load Shedding

Draft 2 of PRC-006-4
January 2020

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PRC-006-4 — Automatic Underfrequency Load Shedding

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 R9:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a Planning Coordinator (PC)
assessment. The revised language adds clarity by requiring that each UFLS entity follow the
UFLS program, including any Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R10:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a PC assessment. The revised
language adds clarity by requiring that each UFLS entity follow the UFLS program, including any
Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R15:
Requirement R15 was added in response to the directive from FERC Order No. 763, which
raised concern that the standard failed to specify how soon an entity would need to implement
corrections after a deficiency is identified by a PC assessment. Requirement R15 addresses the
FERC directive by making explicit that if deficiencies are identified as a result of an assessment,
the PC shall develop a Corrective Action Plan and schedule for implementation by the UFLS
entities.
A “Corrective Action Plan” is defined in the NERC Glossary of Terms as, “a list of actions and an
associated timetable for implementation to remedy a specific problem.” Thus, the Corrective
Action Plan developed by the PC will identify the specific timeframe for an entity to implement
corrections to remedy any deficiencies identified by the PC as a result of an assessment.

Draft 2 of PRC-006-4
January 2020

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PRC-006-4 — Automatic Underfrequency Load Shedding

A. Introduction
1.
Title:
Automatic Underfrequency Load Shedding
2.

Number:

3.

Purpose: To establish design and documentation requirements for automatic
underfrequency load shedding (UFLS) programs to arrest declining frequency, assist
recovery of frequency following underfrequency events and provide last resort
system preservation measures.

4.

Applicability:

PRC-006-4

4.1. Planning Coordinators
4.2. UFLS entities shall mean all entities that are responsible for the ownership,
operation, or control of UFLS equipment as required by the UFLS program
established by the Planning Coordinators. Such entities may include one or
more of the following:
4.2.1 Transmission Owners
4.2.2 Distribution Providers
4.2.3 UFLS-Only Distribution Providers 1
4.3. Transmission Owners that own Elements identified in the UFLS program
established by the Planning Coordinators.
5.

Effective Date:
See Implementation Plan

B. Requirements and Measures
R1.

Each Planning Coordinator shall develop and document criteria, including
consideration of historical events and system studies, to select portions of the Bulk
Electric System (BES), including interconnected portions of the BES in adjacent
Planning Coordinator areas and Regional Entity areas that may form islands. [VRF:
Medium][Time Horizon: Long-term Planning]

M1. Each Planning Coordinator shall have evidence such as reports, or other documentation
of its criteria to select portions of the Bulk Electric System that may form islands
including how system studies and historical events were considered to develop the
criteria per Requirement R1.
R2.

Each Planning Coordinator shall identify one or more islands to serve as a basis for
designing its UFLS program including: [VRF: Medium][Time Horizon: Long-term
Planning]

NERC Rules of Procedure, Appendix 5
https://www.nerc.com/FilingsOrders/us/RuleOfProcedureDL/NERC_ROP_Effective_20160504.pdf
1

Draft 1 2 of PRC-006-4
October January 20192020

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PRC-006-4 — Automatic Underfrequency Load Shedding

2.1. Those islands selected by applying the criteria in Requirement R1, and
2.2. Any portions of the BES designed to detach from the Interconnection (planned
islands) as a result of the operation of a relay scheme or Special Protection
System, and
2.3. A single island that includes all portions of the BES in either the Regional Entity
area or the Interconnection in which the Planning Coordinator’s area resides. If a
Planning Coordinator’s area resides in multiple Regional Entity areas, each of
those Regional Entity areas shall be identified as an island. Planning Coordinators
may adjust island boundaries to differ from Regional Entity area boundaries by
mutual consent where necessary for the sole purpose of producing contiguous
regional islands more suitable for simulation.
M2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s) as a basis
for designing a UFLS program that meet the criteria in Requirement R2, Parts 2.1
through 2.3.
R3.

Each Planning Coordinator shall develop a UFLS program, including notification of and
a schedule for implementation by UFLS entities within its area, that meets the
following performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s). [VRF:
High][Time Horizon: Long-term Planning]
3.1. Frequency shall remain above the Underfrequency Performance Characteristic
curve in PRC-006-3 4 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
3.2. Frequency shall remain below the Overfrequency Performance Characteristic
curve in PRC-006-3 4 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
3.3. Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two seconds
cumulatively per simulated event, and shall not exceed 1.10 per unit for longer
than 45 seconds cumulatively per simulated event at each generator bus and
generator step-up transformer high-side bus associated with each of the
following:
• Individual generating units greater than 20 MVA (gross nameplate rating)
directly connected to the BES
• Generating plants/facilities greater than 75 MVA (gross aggregate nameplate
rating) directly connected to the BES
• Facilities consisting of one or more units connected to the BES at a common
bus with total generation above 75 MVA gross nameplate rating.

Draft 1 2 of PRC-006-4
October January 2019r 20
40

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PRC-006-4 — Automatic Underfrequency Load Shedding

M3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its UFLS program, including the
notification of the UFLS entities of implementation schedule, that meet the criteria in
Requirement R3, Parts 3.1 through 3.3.
R4.

Each Planning Coordinator shall conduct and document a UFLS design assessment at
least once every five years that determines through dynamic simulation whether the
UFLS program design meets the performance characteristics in Requirement R3 for
each island identified in Requirement R2. The simulation shall model each of the
following: [VRF: High][Time Horizon: Long-term Planning]
4.1. Underfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip above the
Generator Underfrequency Trip Modeling curve in PRC-006-3 4 - Attachment 1.
4.2. Underfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip above
the Generator Underfrequency Trip Modeling curve in PRC-006-3 4 - Attachment
1.
4.3. Underfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-3 4 - Attachment 1.
4.4. Overfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-3 4 — Attachment 1.
4.5. Overfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip below
the Generator Overfrequency Trip Modeling curve in PRC-006-3 4 — Attachment
1.
4.6. Overfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-3 4 — Attachment 1.
4.7. Any automatic Load restoration that impacts frequency stabilization and operates
within the duration of the simulations run for the assessment.

M4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its UFLS design
assessment that demonstrates it meets Requirement R4, Parts 4.1 through 4.7.
R5.

Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall coordinate its UFLS program design

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with all other Planning Coordinators whose areas or portions of whose areas are also
part of the same identified island through one of the following: [VRF: High][Time
Horizon: Long-term Planning]
•

Develop a common UFLS program design and schedule for implementation per
Requirement R3 among the Planning Coordinators whose areas or portions of
whose areas are part of the same identified island, or

•

Conduct a joint UFLS design assessment per Requirement R4 among the Planning
Coordinators whose areas or portions of whose areas are part of the same
identified island, or

•

Conduct an independent UFLS design assessment per Requirement R4 for the
identified island, and in the event the UFLS design assessment fails to meet
Requirement R3, identify modifications to the UFLS program(s) to meet
Requirement R3 and report these modifications as recommendations to the other
Planning Coordinators whose areas or portions of whose areas are also part of
the same identified island and the ERO.

M5. Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall have dated evidence such as joint
UFLS program design documents, reports describing a joint UFLS design assessment,
letters that include recommendations, or other dated documentation demonstrating
that it coordinated its UFLS program design with all other Planning Coordinators whose
areas or portions of whose areas are also part of the same identified island per
Requirement R5.
R6.

Each Planning Coordinator shall maintain a UFLS database containing data necessary to
model its UFLS program for use in event analyses and assessments of the UFLS
program at least once each calendar year, with no more than 15 months between
maintenance activities. [VRF: Lower][Time Horizon: Long-term Planning]

M6. Each Planning Coordinator shall have dated evidence such as a UFLS database, data
requests, data input forms, or other dated documentation to show that it maintained a
UFLS database for use in event analyses and assessments of the UFLS program per
Requirement R6 at least once each calendar year, with no more than 15 months
between maintenance activities.
R7.

Each Planning Coordinator shall provide its UFLS database containing data necessary to
model its UFLS program to other Planning Coordinators within its Interconnection
within 30 calendar days of a request. [VRF: Lower][Time Horizon: Long-term Planning]

M7. Each Planning Coordinator shall have dated evidence such as letters, memorandums,
e-mails or other dated documentation that it provided their UFLS database to other
Planning Coordinators within their Interconnection within 30 calendar days of a
request per Requirement R7.

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R8.

Each UFLS entity shall provide data to its Planning Coordinator(s) according to the
format and schedule specified by the Planning Coordinator(s) to support maintenance
of each Planning Coordinator’s UFLS database. [VRF: Lower][Time Horizon: Long-term
Planning]

M8. Each UFLS Entity shall have dated evidence such as responses to data requests,
spreadsheets, letters or other dated documentation that it provided data to its
Planning Coordinator according to the format and schedule specified by the Planning
Coordinator to support maintenance of the UFLS database per Requirement R8.
R9.

Each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
as determined by its Planning Coordinator(s) in each Planning Coordinator area in
which it owns assets. [VRF: High][Time Horizon: Long-term Planning]

M9. Each UFLS Entity shall have dated evidence such as spreadsheets summarizing feeder
load armed with UFLS relays, spreadsheets with UFLS relay settings, or other dated
documentation that it provided automatic tripping of load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
per Requirement R9.
R10. Each Transmission Owner shall provide automatic switching of its existing capacitor
banks, Transmission Lines, and reactors to control over-voltage as a result of
underfrequency load shedding if required by the UFLS program and schedule for
implementation, including any Corrective Action Plan, as determined by the Planning
Coordinator(s) in each Planning Coordinator area in which the Transmission Owner
owns transmission. [VRF: High][Time Horizon: Long-term Planning]
M10. Each Transmission Owner shall have dated evidence such as relay settings, tripping
logic or other dated documentation that it provided automatic switching of its existing
capacitor banks, Transmission Lines, and reactors in order to control over-voltage as a
result of underfrequency load shedding if required by the UFLS program and schedule
for implementation, including any Corrective Action Plan, per Requirement R10.
R11. Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
conduct and document an assessment of the event within one year of event actuation
to evaluate: [VRF: Medium][Time Horizon: Operations Assessment]
11.1. The performance of the UFLS equipment,
11.2. The effectiveness of the UFLS program.
M11. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted an
event assessment of the performance of the UFLS equipment and the effectiveness of
the UFLS program per Requirement R11.

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R12. Each Planning Coordinator, in whose islanding event assessment (per R11) UFLS
program deficiencies are identified, shall conduct and document a UFLS design
assessment to consider the identified deficiencies within two years of event actuation.
[VRF: Medium][Time Horizon: Operations Assessment]
M12. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted a
UFLS design assessment per Requirements R12 and R4 if UFLS program deficiencies are
identified in R11.
R13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall coordinate its event assessment (in accordance
with Requirement R11) with all other Planning Coordinators whose areas or portions of
whose areas were also included in the same islanding event through one of the
following: [VRF: Medium][Time Horizon: Operations Assessment]
•

Conduct a joint event assessment per Requirement R11 among the Planning
Coordinators whose areas or portions of whose areas were included in the same
islanding event, or

•

Conduct an independent event assessment per Requirement R11 that reaches
conclusions and recommendations consistent with those of the event
assessments of the other Planning Coordinators whose areas or portions of
whose areas were included in the same islanding event, or

•

Conduct an independent event assessment per Requirement R11 and where the
assessment fails to reach conclusions and recommendations consistent with
those of the event assessments of the other Planning Coordinators whose areas
or portions of whose areas were included in the same islanding event, identify
differences in the assessments that likely resulted in the differences in the
conclusions and recommendations and report these differences to the other
Planning Coordinators whose areas or portions of whose areas were included in
the same islanding event and the ERO.

M13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall have dated evidence such as a joint assessment
report, independent assessment reports and letters describing likely reasons for
differences in conclusions and recommendations, or other dated documentation
demonstrating it coordinated its event assessment (per Requirement R11) with all
other Planning Coordinator(s) whose areas or portions of whose areas were also
included in the same islanding event per Requirement R13.

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R14. Each Planning Coordinator shall respond to written comments submitted by UFLS
entities and Transmission Owners within its Planning Coordinator area following a
comment period and before finalizing its UFLS program, indicating in the written
response to comments whether changes will be made or reasons why changes will not
be made to the following [VRF: Lower][Time Horizon: Long-term Planning]:
14.1. UFLS program, including a schedule for implementation
14.2. UFLS design assessment
14.3. Format and schedule of UFLS data submittal
M14. Each Planning Coordinator shall have dated evidence of responses, such as e-mails and
letters, to written comments submitted by UFLS entities and Transmission Owners
within its Planning Coordinator area following a comment period and before finalizing
its UFLS program per Requirement R14.
R15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall develop a Corrective Action Plan
and a schedule for implementation by the UFLS entities within its area. [VRF:
High][Time Horizon: Long-term Planning]
15.1. For UFLS design assessments performed under Requirement R4 or R5, the
Corrective Action Plan shall be developed within the five-year time frame
identified in Requirement R4.
15.2. For UFLS design assessments performed under Requirement R12, the Corrective
Action Plan shall be developed within the two-year time frame identified in
Requirement R12.
M15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall have a dated Corrective Action
Plan and a schedule for implementation by the UFLS entities within its area, that was
developed within the time frame identified in Part 15.1 or 15.2.

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C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
Each Planning Coordinator and UFLS entity shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
•

Each Planning Coordinator shall retain the current evidence of Requirements
R1, R2, R3, R4, R5, R12, R14, and R15, Measures M1, M2, M3, M4, M5, M12,
M14, and M15 as well as any evidence necessary to show compliance since
the last compliance audit.

•

Each Planning Coordinator shall retain the current evidence of UFLS database
update in accordance with Requirement R6, Measure M6, and evidence of the
prior year’s UFLS database update.

•

Each Planning Coordinator shall retain evidence of any UFLS database
transmittal to another Planning Coordinator since the last compliance audit in
accordance with Requirement R7, Measure M7.

•

Each UFLS entity shall retain evidence of UFLS data transmittal to the Planning
Coordinator(s) since the last compliance audit in accordance with
Requirement R8, Measure M8.

•

Each UFLS entity shall retain the current evidence of adherence with the UFLS
program in accordance with Requirement R9, Measure M9, and evidence of
adherence since the last compliance audit.

•

Transmission Owner shall retain the current evidence of adherence with the
UFLS program in accordance with Requirement R10, Measure M10, and
evidence of adherence since the last compliance audit.

•

Each Planning Coordinator shall retain evidence of Requirements R11, and
R13, and Measures M11, and M13 for 6 calendar years.

If a Planning Coordinator or UFLS entity is found non-compliant, it shall keep
information related to the non-compliance until found compliant or for the
retention period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
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1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaints
1.4. Additional Compliance Information
None

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Violation Severity Levels
R#
R1

Lower VSL
N/A

Moderate VSL

High VSL

Severe VSL

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas that may
form islands.

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events and system studies, to
select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas
and Regional Entity areas, that
may form islands.

The Planning Coordinator failed
to develop and document
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas and
Regional Entity areas, that may
form islands.

The Planning Coordinator
identified an island(s) to serve

The Planning Coordinator
identified an island(s) to serve

OR
The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of system
studies, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas, that
may form islands.
R2

N/A
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The Planning Coordinator
identified an island(s) to
20

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R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

serve as a basis for designing
its UFLS program but failed to
include one (1) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its
UFLS program but failed to
include two (2) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its UFLS
program but failed to include all
of the Parts as specified in
Requirement R2, Parts 2.1, 2.2,
or 2.3.
OR
The Planning Coordinator failed
to identify any island(s) to serve
as a basis for designing its UFLS
program.

R3

N/A

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation
by UFLS entities within its
area where imbalance = [(load
— actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet one (1) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of
underfrequency conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation
by UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet two (2) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of underfrequency
conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified
island(s).,but failed to meet all
the performance characteristic
in Requirement R3, Parts 3.1,
3.2, and 3.3 in simulations of
underfrequency conditions.
OR
The Planning Coordinator failed
to develop a UFLS program

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R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
including notification of and a
schedule for implementation by
UFLS entities within its area

R4

The Planning Coordinator
conducted and documented a
UFLS assessment at least
once every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics
in Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
one (1) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

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The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
two (2) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

20

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
three (3) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
R3 but simulation failed to
include four (4) or more of the
items as specified in
Requirement R4, Parts 4.1
through 4.7.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
R3 for each island identified in
Requirement R2

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R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R5

N/A

N/A

N/A

The Planning Coordinator, whose
area or portions of whose area is
part of an island identified by it
or another Planning Coordinator
which includes multiple Planning
Coordinator areas or portions of
those areas, failed to coordinate
its UFLS program design through
one of the manners described in
Requirement R5.

R6

N/A

N/A

N/A

The Planning Coordinator failed
to maintain a UFLS database for
use in event analyses and
assessments of the UFLS
program at least once each
calendar year, with no more
than 15 months between
maintenance activities.

R7

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 30 calendar days
and up to and including 40
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 40 calendar days
but less than and including 50
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 50 calendar days
but less than and including 60
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 60 calendar days
following the request.

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OR

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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator failed
to provide its UFLS database to
other Planning Coordinators.

R8

The UFLS entity provided data
to its Planning Coordinator(s)
less than or equal to 10
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 10 calendar days
but less than or equal to 15
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 15 calendar days
but less than or equal to 20
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data to
its Planning Coordinator(s) more
than 20 calendar days following
the schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided less
than 90% but more than (and
including) 85% of automatic
tripping of Load in accordance
with the UFLS program design

The UFLS entity provided less
than 85% of automatic tripping
of Load in accordance with the
UFLS program design and
schedule for implementation,

OR
The UFLS entity provided data
to its Planning Coordinator(s)
but the data was not
according to the format
specified by the Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.
R9

The UFLS entity provided less
than 100% but more than
(and including) 95% of
automatic tripping of Load in
accordance with the UFLS
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The UFLS entity provided less
than 95% but more than (and
including) 90% of automatic
tripping of Load in accordance
with the UFLS program design
20

OR
The UFLS entity failed to provide
data to its Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.

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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

program design and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which
it owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

including any Corrective Action
Plan, as determined by the
Planning Coordinator(s) area in
which it owns assets.

R10

The Transmission Owner
provided less than 100% but
more than (and including)
95% automatic switching of
its existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 95% but
more than (and including)
90% automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 90% but
more than (and including) 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the UFLS
program and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission Owner
owns transmission.

The Transmission Owner
provided less than 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and reactors
to control over-voltage if
required by the UFLS program
and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each Planning
Coordinator area in which the
Transmission Owner owns
transmission.

R11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of the

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,

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Severe VSL

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R#

Lower VSL

Moderate VSL

High VSL

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than one year
but less than or equal to 13
months of actuation.

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than 13 months
but less than or equal to 14
months of actuation.

UFLS program, conducted and
documented an assessment of
the event and evaluated the
parts as specified in
Requirement R11, Parts 11.1
and 11.2 within a time greater
than 14 months but less than
or equal to 15 months of
actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the
initializing set points of the
UFLS program, conducted and
documented an assessment of
the event within one year of
event actuation but failed to
evaluate one (1) of the Parts
as specified in Requirement
R11, Parts11.1 or 11.2.

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Severe VSL
conducted and documented an
assessment of the event and
evaluated the parts as specified
in Requirement R11, Parts 11.1
and 11.2 within a time greater
than 15 months of actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to conduct and document
an assessment of the event and
evaluate the Parts as specified in
Requirement R11, Parts 11.1 and
11.2.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
conducted and documented an
assessment of the event within
one year of event actuation but
failed to evaluate all of the Parts

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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
as specified in Requirement R11,
Parts 11.1 and 11.2.

R12

R13

N/A

N/A

Draft 1 2 of PRC-006-4
October January 2019r

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than two
years but less than or equal to
25 months of event actuation.

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than 25
months but less than or equal
to 26 months of event
actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, conducted and documented
a UFLS design assessment to
consider the identified
deficiencies greater than 26
months of event actuation.

N/A

N/A

The Planning Coordinator, in
whose area a BES islanding event
occurred that also included the
area(s) or portions of area(s) of
other Planning Coordinator(s) in
the same islanding event and
that resulted in system
frequency excursions below the
initializing set points of the UFLS

20

OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, failed to conduct and
document a UFLS design
assessment to consider the
identified deficiencies.

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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
program, failed to coordinate its
UFLS event assessment with all
other Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event in
one of the manners described in
Requirement R13

R14

N/A

N/A

N/A

The Planning Coordinator failed
to respond to written comments
submitted by UFLS entities and
Transmission Owners within its
Planning Coordinator area
following a comment period and
before finalizing its UFLS
program, indicating in the
written response to comments
whether changes were made or
reasons why changes were not
made to the items in Parts 14.1
through 14.3.

R15

N/A

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance

Draft 1 2 of PRC-006-4
October January 2019r

20

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PRC-006-4 — Automatic Underfrequency Load Shedding

R#

Lower VSL

Draft 1 2 of PRC-006-4
October January 2019r

Moderate VSL

High VSL

Severe VSL

characteristics in Requirement
R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period of
up to 1 month.

characteristics in Requirement
R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period
greater than 1 month but not
more than 2 months.

characteristics in Requirement
R3, but failed to develop a
Corrective Action Plan and a
schedule for implementation by
the UFLS entities within its area.

20

OR
The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance
characteristics in Requirement
R3, and developed a Corrective
Action Plan and a schedule for
implementation by the UFLS
entities within its area, but
exceeded the permissible time
frame for development by a
period greater than 2 months.

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PRC-006-4 — Automatic Underfrequency Load Shedding

D. Regional Variances
D.A. Regional Variance for the Quebec Interconnection
The following Interconnection-wide variance shall be applicable in the Quebec
Interconnection and replaces, in their entirety, Requirements R3 and R4 and the
violation severity levels associated with Requirements R3 and R4.
Rationale for Requirement D.A.3:
There are two modifications for requirement D.A.3 :
1. 25% Generation Deficiency : Since the Quebec Interconnection has no potential
viable BES Island in underfrequency conditions, the largest generation deficiency
scenarios are limited to extreme contingencies not already covered by RAS.
Based on Hydro-Québec TransÉnergie Transmission Planning requirements, the
stability of the network shall be maintained for extreme contingencies using a case
representing internal transfers not expected to be exceeded 25% of the time.
The Hydro-Québec TransÉnergie defense plan to cover these extreme contingencies
includes two RAS (RPTC- generation rejection and remote load shedding and TDST a centralized UVLS) and the UFLS.
2. Frequency performance curve (attachment 1A) : Specific cases where a small
generation deficiency using a peak case scenario with the minimum requirement of
spinning reserve can lead to an acceptable frequency deviation in the Quebec
Interconnection while stabilizing between the PRC-006-2 requirement (59.3 Hz) and
the UFLS anti-stall threshold (59.0 Hz).
An increase of the anti-stall threshold to 59.3 Hz would correct this situation but would
cause frequent load shedding of customers without any gain of system reliability.
Therefore, it is preferable to lower the steady state frequency minimum value to 59.0
Hz.
The delay in the performance characteristics curve is harmonized between D.A.3 and
R.3 to 60 seconds.
Rationale for Requirements D.A.3.3. and D.A.4:
The Quebec Interconnection has its own definition of BES. In Quebec, the vast
majority of BES generating plants/facilities are not directly connected to the BES. For
simulations to take into account sufficient generating resources D.A.3.3 and D.A.4
need simply refer to BES generators, plants or facilities since these are listed in a
Registry approved by Québec’s Regulatory Body (Régie de l’Énergie).

D.A.3. Each Planning Coordinator shall develop a UFLS program, including notification
of and a schedule for implementation by UFLS entities within its area, that
meets the following performance characteristics in simulations of
underfrequency conditions resulting from each of these extreme events:
Draft 1 2 of PRC-006-4
October January 20192020

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PRC-006-4 — Automatic Underfrequency Load Shedding

•

Loss of the entire capability of a generating station.

•

Loss of all transmission circuits emanating from a generating station,
switching station, substation or dc terminal.

•

Loss of all transmission circuits on a common right-of-way.

•

Three-phase fault with failure of a circuit breaker to operate and correct
operation of a breaker failure protection system and its associated breakers.

•

Three-phase fault on a circuit breaker, with normal fault clearing.

•

The operation or partial operation of a RAS for an event or condition for
which it was not intended to operate.

[VRF: High][Time Horizon: Long-term Planning]
D.A.3.1.

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-3 4 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-3 4 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than
two seconds cumulatively per simulated event, and shall not exceed
1.10 per unit for longer than 45 seconds cumulatively per simulated
event at each Quebec BES generator bus and associated generator
step-up transformer high-side bus

M.D.A.3. Each Planning Coordinator shall have evidence such as reports,
memorandums, e-mails, program plans, or other documentation of its UFLS
program, including the notification of the UFLS entities of implementation
schedule, that meet the criteria in Requirement D.A.3 Parts D.A.3.1 through
D.A.3.3.
D.A.4. Each Planning Coordinator shall conduct and document a UFLS design
assessment at least once every five years that determines through dynamic
simulation whether the UFLS program design meets the performance
characteristics in Requirement D.A.3 for each island identified in Requirement
R2. The simulation shall model each of the following; [VRF: High][Time
Horizon: Long-term Planning]

Draft 1 2 of PRC-006-4
October January 20192020

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PRC-006-4 — Automatic Underfrequency Load Shedding

D.A.4.1

Underfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip above the Generator
Underfrequency Trip Modeling curve in PRC-006-3 4 - Attachment
1A, and

D.A.4.2

Overfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip below the Generator
Overfrequency Trip Modeling curve in PRC-006-3 4 - Attachment
1A, and

D.A.4.3

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.A.4. Each Planning Coordinator shall have dated evidence such as reports,
dynamic simulation models and results, or other dated documentation of its
UFLS design assessment that demonstrates it meets Requirement D.A.4
Parts D.A.4.1 through D.A.4.3.

Draft 1 2 of PRC-006-4
October January 20192020

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#
DA3

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet two (2) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

Severe VSL
The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Parts D.A.3.1, D.A.3.2, and
D.A.3.3 in simulations of
underfrequency conditions
OR
The Planning Coordinator failed
to develop a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area.

DA4

N/A

Draft 1 2 of PRC-006-4
October January 20192020

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed
to include one (1) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include two (2) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include all of the items as

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL
specified in Parts D.A.4.1,
D.A.4.2 or D.A.4.3.

High VSL

Severe VSL

specified in Parts D.A.4.1, D.A.4.2
or D.A.4.3.

specified in Parts D.A.4.1, D.A.4.2
and D.A.4.3.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.A.3

Draft 1 2 of PRC-006-4
October January 20192020

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PRC-006-4 — Automatic Underfrequency Load Shedding

D.B.

Regional Variance for the Western Electricity Coordinating Council
The following Interconnection-wide variance shall be applicable in the Western
Electricity Coordinating Council (WECC) and replaces, in their entirety, Requirements R1,
R2, R3, R4, R5, R11, R12, and R13.
D.B.1. Each Planning Coordinator shall participate in a joint regional review with the
other Planning Coordinators in the WECC Regional Entity area that develops and
documents criteria, including consideration of historical events and system
studies, to select portions of the Bulk Electric System (BES) that may form
islands. [VRF: Medium][Time Horizon: Long-term Planning]
M.D.B.1. Each Planning Coordinator shall have evidence such as reports, or other
documentation of its criteria, developed as part of the joint regional review
with other Planning Coordinators in the WECC Regional Entity area to select
portions of the Bulk Electric System that may form islands including how system
studies and historical events were considered to develop the criteria per
Requirement D.B.1.
D.B.2. Each Planning Coordinator shall identify one or more islands from the regional
review (per D.B.1) to serve as a basis for designing a region-wide coordinated
UFLS program including: [VRF: Medium][Time Horizon: Long-term Planning]
D.B.2.1. Those islands selected by applying the criteria in Requirement D.B.1,
and
D.B.2.2. Any portions of the BES designed to detach from the Interconnection
(planned islands) as a result of the operation of a relay scheme or
Special Protection System.
M.D.B.2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s),
from the regional review (per D.B.1), as a basis for designing a region-wide
coordinated UFLS program that meet the criteria in Requirement D.B.2 Parts
D.B.2.1 and D.B.2.2.
D.B.3. Each Planning Coordinator shall adopt a UFLS program, coordinated across the
WECC Regional Entity area, including notification of and a schedule for
implementation by UFLS entities within its area, that meets the following
performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s).
[VRF: High][Time Horizon: Long-term Planning]
D.B.3.1.

Draft 1 2 of PRC-006-4
October January 20192020

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-3 4 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and

Page 25 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

D.B.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-34 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and

D.B.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two
seconds cumulatively per simulated event, and shall not exceed 1.10
per unit for longer than 45 seconds cumulatively per simulated event
at each generator bus and generator step-up transformer high-side
bus associated with each of the following:
D.B.3.3.1. Individual generating units greater than 20 MVA (gross
nameplate rating) directly connected to the BES
D.B.3.3.2. Generating plants/facilities greater than 75 MVA (gross
aggregate nameplate rating) directly connected to the
BES
D.B.3.3.3. Facilities consisting of one or more units connected to
the BES at a common bus with total generation above 75
MVA gross nameplate rating.

M.D.B.3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its adoption of a UFLS
program, coordinated across the WECC Regional Entity area, including the
notification of the UFLS entities of implementation schedule, that meet the
criteria in Requirement D.B.3 Parts D.B.3.1 through D.B.3.3.
D.B.4. Each Planning Coordinator shall participate in and document a coordinated
UFLS design assessment with the other Planning Coordinators in the WECC
Regional Entity area at least once every five years that determines through
dynamic simulation whether the UFLS program design meets the performance
characteristics in Requirement D.B.3 for each island identified in Requirement
D.B.2. The simulation shall model each of the following: [VRF: High][Time
Horizon: Long-term Planning]
D.B.4.1.

Underfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip above the Generator Underfrequency Trip Modeling curve
in PRC-006-3 4 - Attachment 1.

D.B.4.2.

Underfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-3 4 - Attachment 1.

D.B.4.3.

Underfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
above 75 MVA (gross nameplate rating) that trip above the

Draft 1 2 of PRC-006-4
October January 20192020

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PRC-006-4 — Automatic Underfrequency Load Shedding

Generator Underfrequency Trip Modeling curve in PRC-006-3 4 Attachment 1.
D.B.4.4.

Overfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip below the Generator Overfrequency Trip Modeling curve in
PRC-006-3 4 — Attachment 1.

D.B.4.5.

Overfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-3 4 — Attachment 1.

D.B.4.6.

Overfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
above 75 MVA (gross nameplate rating) that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-3 4 —
Attachment 1.

D.B.4.7.

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.B.4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its participation
in a coordinated UFLS design assessment with the other Planning Coordinators in
the WECC Regional Entity area that demonstrates it meets Requirement D.B.4
Parts D.B.4.1 through D.B.4.7.
D.B.11.

Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
participate in and document a coordinated event assessment with all affected
Planning Coordinators to conduct and document an assessment of the event
within one year of event actuation to evaluate: [VRF: Medium][Time Horizon:
Operations Assessment]
D.B.11.1. The performance of the UFLS equipment,
D.B.11.2 The effectiveness of the UFLS program

M.D.B.11. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a coordinated event assessment of the performance of the UFLS
equipment and the effectiveness of the UFLS program per Requirement D.B.11.
D.B.12.

Each Planning Coordinator, in whose islanding event assessment (per D.B.11)
UFLS program deficiencies are identified, shall participate in and document a
coordinated UFLS design assessment of the UFLS program with the other

Draft 1 2 of PRC-006-4
October January 20192020

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PRC-006-4 — Automatic Underfrequency Load Shedding

Planning Coordinators in the WECC Regional Entity area to consider the
identified deficiencies within two years of event actuation. [VRF: Medium][Time
Horizon: Operations Assessment]
M.D.B.12. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a UFLS design assessment per Requirements D.B.12 and D.B.4 if
UFLS program deficiencies are identified in D.B.11.

Draft 1 2 of PRC-006-4
October January 20192020

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#
D.B.1

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical
events, to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical events
and system studies, to select
portions of the BES, including
interconnected portions of the
BES in adjacent Planning
Coordinator areas, that may form
islands

OR

Severe VSL
The Planning Coordinator failed
to participate in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of system studies,
to select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands

Draft 1 2 of PRC-006-4
October January 20192020

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#
D.B.2

Lower VSL

Moderate VSL

High VSL

N/A
N/A

The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include one
(1) of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2

Severe VSL
The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include all
of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2
OR
The Planning Coordinator failed
to identify any island(s) from the
regional review to serve as a
basis for designing its UFLS
program.

D.B.3

N/A

Draft 1 2 of PRC-006-4
October January 20192020

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, or D.B.3.3 in
simulations of underfrequency
conditions

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that included
notification of and a schedule for
implementation by UFLS entities
within its area, but failed to meet
two (2) of the performance
characteristic in Requirement
D.B.3, Parts D.B.3.1, D.B.3.2, or
D.B.3.3 in simulations of
underfrequency conditions

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, and D.B.3.3 in
simulations of underfrequency
conditions

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
OR
The Planning Coordinator failed
to adopt a UFLS program,
coordinated across the WECC
Regional Entity area, including
notification of and a schedule for
implementation by UFLS entities
within its area.

D.B.4

The Planning Coordinator
participated in and
documented a coordinated
UFLS assessment with the other
Planning Coordinators in the
WECC Regional Entity area at
least once every five years that
determines through dynamic
simulation whether the UFLS
program design meets the
performance characteristics in
Requirement D.B.3 for each
island identified in Requirement
D.B.2 but the simulation failed
to include one (1) of the items
as specified in Requirement
D.B.4, Parts D.B.4.1 through
D.B.4.7.

Draft 1 2 of PRC-006-4
October January 20192020

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include two
(2) of the items as specified in
Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include three
(3) of the items as specified in
Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include four
(4) or more of the items as
specified in Requirement D.B.4,
Parts D.B.4.1 through D.B.4.7.
OR

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PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator failed
to participate in and document a
coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2

D.B.11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below the
initializing set points of the
UFLS program, participated in
and documented a coordinated
event assessment with all
Planning Coordinators whose
areas or portions of whose
areas were also included in the
same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than one year but
Draft 1 2 of PRC-006-4
October January 20192020

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 13 months but

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 14 months but

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a

Page 32 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL
less than or equal to 13 months
of actuation.

Draft 1 2 of PRC-006-4
October January 20192020

Moderate VSL
less than or equal to 14 months
of actuation.

High VSL

Severe VSL

less than or equal to 15 months
of actuation.

time greater than 15 months of
actuation.

OR

OR

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event
within one year of event
actuation but failed to evaluate
one (1) of the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 or D.B.11.2.

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to participate in and
document a coordinated event
assessment with all Planning
Coordinators whose areas or
portion of whose areas were also
included in the same island event
and evaluate the parts as
specified in Requirement D.B.11,
Parts D.B.11.1 and D.B.11.2.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included

Page 33 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
in the same islanding event
within one year of event
actuation but failed to evaluate
all of the parts as specified in
Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2.

D.B.12

N/A

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than two
years but less than or equal to 25
months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 25
months but less than or equal to
26 months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 26
months of event actuation.
OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, failed to participate in
and document a coordinated
UFLS design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area

Draft 1 2 of PRC-006-4
October January 20192020

Page 34 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
to consider the identified
deficiencies

Draft 1 2 of PRC-006-4
October January 20192020

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PRC-006-4 — Automatic Underfrequency Load Shedding

E. Associated Documents
Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

May 25, 2010

Completed revision, merging and
updating PRC-006-0, PRC-007-0 and
PRC-009-0.

1

November 4, 2010

Adopted by the Board of Trustees

1

May 7, 2012

FERC Order issued approving PRC006-1 (approval becomes effective
July 10, 2012)

1

November 9, 2012

2

November 13, 2014

FERC Letter Order issued accepting
the modification of the VRF in R5
from (Medium to High) and the
modification of the VSL language in
R8.
Adopted by the Board of Trustees

Revisions made under
Project 2008-02:
Undervoltage Load
Shedding (UVLS) &
Underfrequency Load
Shedding (UFLS) to address
directive issued in FERC
Order No. 763.
Revisions to existing
Requirement R9 and
R10 and addition of
new Requirement
R15.

3

August 10, 2017

4

Draft 1 2 of PRC-006-4
October January 20192020

Adopted by the NERC Board of
Trustees
Adopted by the NERC Board of
Trustees

Revisions to the Regional
Variance for the Quebec
Interconnection.

Page 36 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

PRC-006-3 4 – Attachment 1
Underfrequency Load Shedding Program
Design Performance and Modeling Curves for
Requirements R3 Parts 3.1-3.2 and R4 Parts 4.1-4.6
63

Overfrequency Trip Settings
Must Be Modeled for Generators
That Trip Below the Generator
Overfrequency Trip Modeling
Curve

62

Simulated Frequency Must
Remain Between the
Overfrequency and
Underfrequency Performance
Characteristic Curves

60

59

58

Underfrequency Trip Settings
Must Be Modeled for Generators
That Trip Above the Generator
Underfrequency Trip Modeling
Curve

57
0.1

1

Time (sec)

10

100

Generator Overfrequency Trip Modeling (Requirement R4 Parts 4.4-4.6)
Overfrequency Performance Characteristic (Requirement R3 Part 3.2)
Underfrequency Performance Characteristic (Requirement R3 Part 3.1)
Generator Underfrequency Trip Modeling (Requirement R4 Parts 4.1-4.3)

Curve Definitions
Generator Overfrequency Trip Modeling

Overfrequency Performance Characteristic

t≤2s

t>2s

t≤4s

4 s < t ≤ 30 s

t > 30 s

f = 62.2
Hz

f = -0.686log(t) + 62.41
Hz

f = 61.8
Hz

f = -0.686log(t) + 62.21
Hz

f = 60.7
Hz

Draft 1 2 of PRC-006-4
October January 20192020

Page 37 of 40

Frequency (Hz)

61

PRC-006-4 — Automatic Underfrequency Load Shedding

Generator Underfrequency Trip
Modeling

Underfrequency Performance Characteristic

t≤2s

t>2s

t≤2s

2 s < t ≤ 60 s

t > 60 s

f = 57.8
Hz

f = 0.575log(t) + 57.63
Hz

f = 58.0
Hz

f = 0.575log(t) + 57.83
Hz

f = 59.3
Hz

Draft 1 2 of PRC-006-4
October January 20192020

Page 38 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

Draft 1 2 of PRC-006-4
October January 20192020

Page 39 of 40

PRC-006-4 — Automatic Underfrequency Load Shedding

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 R9:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a Planning Coordinator (PC)
assessment. The revised language adds clarity by requiring that each UFLS entity follow the
UFLS program, including any Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R10:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a PC assessment. The revised
language adds clarity by requiring that each UFLS entity follow the UFLS program, including any
Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R15:
Requirement R15 was added in response to the directive from FERC Order No. 763, which
raised concern that the standard failed to specify how soon an entity would need to implement
corrections after a deficiency is identified by a PC assessment. Requirement R15 addresses the
FERC directive by making explicit that if deficiencies are identified as a result of an assessment,
the PC shall develop a Corrective Action Plan and schedule for implementation by the UFLS
entities.
A “Corrective Action Plan” is defined in the NERC Glossary of Terms as, “a list of actions and an
associated timetable for implementation to remedy a specific problem.” Thus, the Corrective
Action Plan developed by the PC will identify the specific timeframe for an entity to implement
corrections to remedy any deficiencies identified by the PC as a result of an assessment.

Draft 1 2 of PRC-006-4
October January 20192020

Page 40 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
A. Introduction
1.
Title:
Automatic Underfrequency Load Shedding
2.

Number:

3.

Purpose: To establish design and documentation requirements for automatic
underfrequency load shedding (UFLS) programs to arrest declining frequency, assist
recovery of frequency following underfrequency events and provide last resort
system preservation measures.

4.

Applicability:

PRC-006-3 4

4.1. Planning Coordinators
4.2. UFLS entities shall mean all entities that are responsible for the ownership,
operation, or control of UFLS equipment as required by the UFLS program
established by the Planning Coordinators. Such entities may include one or
more of the following:
4.2.1 Transmission Owners
4.2.2

4.2.2 Distribution Providers
4.2.3 UFLS-Only Distribution Providers1

4.3. Transmission Owners that own Elements identified in the UFLS program
established by the Planning Coordinators.
5.

Effective Date:
See Implementation Plan
This standard is effective on the first day of the first calendar quarter six months 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.

6.

Background:
PRC-006-2 was developed under Project 2008-02: Underfrequency Load Shedding
(UFLS). The drafting team revised PRC-006-1 for the purpose of addressing the
directive issued in FERC Order No. 763. Automatic Underfrequency Load Shedding and
Load Shedding Plans Reliability Standards, 139 FERC ¶ 61,098 (2012).

1

NERC Rules of Procedure, Appendix 5
https://www.nerc.com/FilingsOrders/us/RuleOfProcedureDL/NERC_ROP_Effective_20160504.pdf

Page 1 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
B. Requirements and Measures
R1.

Each Planning Coordinator shall develop and document criteria, including
consideration of historical events and system studies, to select portions of the Bulk
Electric System (BES), including interconnected portions of the BES in adjacent
Planning Coordinator areas and Regional Entity areas that may form islands. [VRF:
Medium][Time Horizon: Long-term Planning]

M1. Each Planning Coordinator shall have evidence such as reports, or other documentation
of its criteria to select portions of the Bulk Electric System that may form islands
including how system studies and historical events were considered to develop the
criteria per Requirement R1.
R2.

Each Planning Coordinator shall identify one or more islands to serve as a basis for
designing its UFLS program including: [VRF: Medium][Time Horizon: Long-term
Planning]
2.1. Those islands selected by applying the criteria in Requirement R1, and
2.2. Any portions of the BES designed to detach from the Interconnection (planned
islands) as a result of the operation of a relay scheme or Special Protection
System, and
2.3. A single island that includes all portions of the BES in either the Regional Entity
area or the Interconnection in which the Planning Coordinator’s area resides. If a
Planning Coordinator’s area resides in multiple Regional Entity areas, each of
those Regional Entity areas shall be identified as an island. Planning Coordinators
may adjust island boundaries to differ from Regional Entity area boundaries by
mutual consent where necessary for the sole purpose of producing contiguous
regional islands more suitable for simulation.

M2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s) as a basis
for designing a UFLS program that meet the criteria in Requirement R2, Parts 2.1
through 2.3.
R3.

Each Planning Coordinator shall develop a UFLS program, including notification of and
a schedule for implementation by UFLS entities within its area, that meets the
following performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s). [VRF:
High][Time Horizon: Long-term Planning]
3.1. Frequency shall remain above the Underfrequency Performance Characteristic
curve in PRC-006-3 4 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
3.2. Frequency shall remain below the Overfrequency Performance Characteristic
curve in PRC-006-3 4 - Attachment 1, either for 60 seconds or until a steady-state
condition between 59.3 Hz and 60.7 Hz is reached, and
Page 2 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
3.3. Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two seconds
cumulatively per simulated event, and shall not exceed 1.10 per unit for longer
than 45 seconds cumulatively per simulated event at each generator bus and
generator step-up transformer high-side bus associated with each of the
following:
• Individual generating units greater than 20 MVA (gross nameplate rating)
directly connected to the BES
• Generating plants/facilities greater than 75 MVA (gross aggregate nameplate
rating) directly connected to the BES
• Facilities consisting of one or more units connected to the BES at a common
bus with total generation above 75 MVA gross nameplate rating.
M3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its UFLS program, including the
notification of the UFLS entities of implementation schedule, that meet the criteria in
Requirement R3, Parts 3.1 through 3.3.
R4.

Each Planning Coordinator shall conduct and document a UFLS design assessment at
least once every five years that determines through dynamic simulation whether the
UFLS program design meets the performance characteristics in Requirement R3 for
each island identified in Requirement R2. The simulation shall model each of the
following: [VRF: High][Time Horizon: Long-term Planning]
4.1. Underfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip above the
Generator Underfrequency Trip Modeling curve in PRC-006-3 4 - Attachment 1.
4.2. Underfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip above
the Generator Underfrequency Trip Modeling curve in PRC-006-3 4 - Attachment
1.
4.3. Underfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-3 4 - Attachment 1.
4.4. Overfrequency trip settings of individual generating units greater than 20 MVA
(gross nameplate rating) directly connected to the BES that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-3 4 — Attachment 1.
4.5. Overfrequency trip settings of generating plants/facilities greater than 75 MVA
(gross aggregate nameplate rating) directly connected to the BES that trip below
the Generator Overfrequency Trip Modeling curve in PRC-006-3 4 — Attachment
1.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
4.6. Overfrequency trip settings of any facility consisting of one or more units
connected to the BES at a common bus with total generation above 75 MVA
(gross nameplate rating) that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-3 4 — Attachment 1.
4.7. Any automatic Load restoration that impacts frequency stabilization and operates
within the duration of the simulations run for the assessment.
M4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its UFLS design
assessment that demonstrates it meets Requirement R4, Parts 4.1 through 4.7.
R5.

Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall coordinate its UFLS program design
with all other Planning Coordinators whose areas or portions of whose areas are also
part of the same identified island through one of the following: [VRF: High][Time
Horizon: Long-term Planning]
•

Develop a common UFLS program design and schedule for implementation per
Requirement R3 among the Planning Coordinators whose areas or portions of
whose areas are part of the same identified island, or

•

Conduct a joint UFLS design assessment per Requirement R4 among the Planning
Coordinators whose areas or portions of whose areas are part of the same
identified island, or

•

Conduct an independent UFLS design assessment per Requirement R4 for the
identified island, and in the event the UFLS design assessment fails to meet
Requirement R3, identify modifications to the UFLS program(s) to meet
Requirement R3 and report these modifications as recommendations to the other
Planning Coordinators whose areas or portions of whose areas are also part of
the same identified island and the ERO.

M5. Each Planning Coordinator, whose area or portions of whose area is part of an island
identified by it or another Planning Coordinator which includes multiple Planning
Coordinator areas or portions of those areas, shall have dated evidence such as joint
UFLS program design documents, reports describing a joint UFLS design assessment,
letters that include recommendations, or other dated documentation demonstrating
that it coordinated its UFLS program design with all other Planning Coordinators whose
areas or portions of whose areas are also part of the same identified island per
Requirement R5.
R6.

Each Planning Coordinator shall maintain a UFLS database containing data necessary to
model its UFLS program for use in event analyses and assessments of the UFLS
program at least once each calendar year, with no more than 15 months between
maintenance activities. [VRF: Lower][Time Horizon: Long-term Planning]

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
M6. Each Planning Coordinator shall have dated evidence such as a UFLS database, data
requests, data input forms, or other dated documentation to show that it maintained a
UFLS database for use in event analyses and assessments of the UFLS program per
Requirement R6 at least once each calendar year, with no more than 15 months
between maintenance activities.
R7.

Each Planning Coordinator shall provide its UFLS database containing data necessary to
model its UFLS program to other Planning Coordinators within its Interconnection
within 30 calendar days of a request. [VRF: Lower][Time Horizon: Long-term Planning]

M7. Each Planning Coordinator shall have dated evidence such as letters, memorandums,
e-mails or other dated documentation that it provided their UFLS database to other
Planning Coordinators within their Interconnection within 30 calendar days of a
request per Requirement R7.
R8.

Each UFLS entity shall provide data to its Planning Coordinator(s) according to the
format and schedule specified by the Planning Coordinator(s) to support maintenance
of each Planning Coordinator’s UFLS database. [VRF: Lower][Time Horizon: Long-term
Planning]

M8. Each UFLS Entity shall have dated evidence such as responses to data requests,
spreadsheets, letters or other dated documentation that it provided data to its
Planning Coordinator according to the format and schedule specified by the Planning
Coordinator to support maintenance of the UFLS database per Requirement R8.
R9.

Each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
as determined by its Planning Coordinator(s) in each Planning Coordinator area in
which it owns assets. [VRF: High][Time Horizon: Long-term Planning]

M9. Each UFLS Entity shall have dated evidence such as spreadsheets summarizing feeder
load armed with UFLS relays, spreadsheets with UFLS relay settings, or other dated
documentation that it provided automatic tripping of load in accordance with the UFLS
program design and schedule for implementation, including any Corrective Action Plan,
per Requirement R9.
R10. Each Transmission Owner shall provide automatic switching of its existing capacitor
banks, Transmission Lines, and reactors to control over-voltage as a result of
underfrequency load shedding if required by the UFLS program and schedule for
implementation, including any Corrective Action Plan, as determined by the Planning
Coordinator(s) in each Planning Coordinator area in which the Transmission Owner
owns transmission. [VRF: High][Time Horizon: Long-term Planning]
M10. Each Transmission Owner shall have dated evidence such as relay settings, tripping
logic or other dated documentation that it provided automatic switching of its existing
capacitor banks, Transmission Lines, and reactors in order to control over-voltage as a
result of underfrequency load shedding if required by the UFLS program and schedule
for implementation, including any Corrective Action Plan, per Requirement R10.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R11. Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
conduct and document an assessment of the event within one year of event actuation
to evaluate: [VRF: Medium][Time Horizon: Operations Assessment]
11.1. The performance of the UFLS equipment,
11.2. The effectiveness of the UFLS program.
M11. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted an
event assessment of the performance of the UFLS equipment and the effectiveness of
the UFLS program per Requirement R11.
R12. Each Planning Coordinator, in whose islanding event assessment (per R11) UFLS
program deficiencies are identified, shall conduct and document a UFLS design
assessment to consider the identified deficiencies within two years of event actuation.
[VRF: Medium][Time Horizon: Operations Assessment]
M12. Each Planning Coordinator shall have dated evidence such as reports, data gathered
from an historical event, or other dated documentation to show that it conducted a
UFLS design assessment per Requirements R12 and R4 if UFLS program deficiencies are
identified in R11.
R13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall coordinate its event assessment (in accordance
with Requirement R11) with all other Planning Coordinators whose areas or portions of
whose areas were also included in the same islanding event through one of the
following: [VRF: Medium][Time Horizon: Operations Assessment]
•

Conduct a joint event assessment per Requirement R11 among the Planning
Coordinators whose areas or portions of whose areas were included in the same
islanding event, or

•

Conduct an independent event assessment per Requirement R11 that reaches
conclusions and recommendations consistent with those of the event
assessments of the other Planning Coordinators whose areas or portions of
whose areas were included in the same islanding event, or

•

Conduct an independent event assessment per Requirement R11 and where the
assessment fails to reach conclusions and recommendations consistent with
those of the event assessments of the other Planning Coordinators whose areas
or portions of whose areas were included in the same islanding event, identify
differences in the assessments that likely resulted in the differences in the
conclusions and recommendations and report these differences to the other
Planning Coordinators whose areas or portions of whose areas were included in
the same islanding event and the ERO.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
M13. Each Planning Coordinator, in whose area a BES islanding event occurred that also
included the area(s) or portions of area(s) of other Planning Coordinator(s) in the same
islanding event and that resulted in system frequency excursions below the initializing
set points of the UFLS program, shall have dated evidence such as a joint assessment
report, independent assessment reports and letters describing likely reasons for
differences in conclusions and recommendations, or other dated documentation
demonstrating it coordinated its event assessment (per Requirement R11) with all
other Planning Coordinator(s) whose areas or portions of whose areas were also
included in the same islanding event per Requirement R13.
R14. Each Planning Coordinator shall respond to written comments submitted by UFLS
entities and Transmission Owners within its Planning Coordinator area following a
comment period and before finalizing its UFLS program, indicating in the written
response to comments whether changes will be made or reasons why changes will not
be made to the following [VRF: Lower][Time Horizon: Long-term Planning]:
14.1. UFLS program, including a schedule for implementation
14.2. UFLS design assessment
14.3. Format and schedule of UFLS data submittal
M14. Each Planning Coordinator shall have dated evidence of responses, such as e-mails and
letters, to written comments submitted by UFLS entities and Transmission Owners
within its Planning Coordinator area following a comment period and before finalizing
its UFLS program per Requirement R14.
R15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall develop a Corrective Action Plan
and a schedule for implementation by the UFLS entities within its area. [VRF:
High][Time Horizon: Long-term Planning]
15.1. For UFLS design assessments performed under Requirement R4 or R5, the
Corrective Action Plan shall be developed within the five-year time frame
identified in Requirement R4.
15.2. For UFLS design assessments performed under Requirement R12, the Corrective
Action Plan shall be developed within the two-year time frame identified in
Requirement R12.
M15. Each Planning Coordinator that conducts a UFLS design assessment under
Requirement R4, R5, or R12 and determines that the UFLS program does not meet the
performance characteristics in Requirement R3, shall have a dated Corrective Action
Plan and a schedule for implementation by the UFLS entities within its area, that was
developed within the time frame identified in Part 15.1 or 15.2.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” (CEA)
means NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention
Each Planning Coordinator and UFLS entity shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
•

Each Planning Coordinator shall retain the current evidence of Requirements
R1, R2, R3, R4, R5, R12, R14, and R15, Measures M1, M2, M3, M4, M5, M12,
M14, and M15 as well as any evidence necessary to show compliance since
the last compliance audit.

•

Each Planning Coordinator shall retain the current evidence of UFLS database
update in accordance with Requirement R6, Measure M6, and evidence of the
prior year’s UFLS database update.

•

Each Planning Coordinator shall retain evidence of any UFLS database
transmittal to another Planning Coordinator since the last compliance audit in
accordance with Requirement R7, Measure M7.

•

Each UFLS entity shall retain evidence of UFLS data transmittal to the Planning
Coordinator(s) since the last compliance audit in accordance with
Requirement R8, Measure M8.

•

Each UFLS entity shall retain the current evidence of adherence with the UFLS
program in accordance with Requirement R9, Measure M9, and evidence of
adherence since the last compliance audit.

•

Transmission Owner shall retain the current evidence of adherence with the
UFLS program in accordance with Requirement R10, Measure M10, and
evidence of adherence since the last compliance audit.

•

Each Planning Coordinator shall retain evidence of Requirements R11, and
R13, and Measures M11, and M13 for 6 calendar years.

If a Planning Coordinator or UFLS entity is found non-compliant, it shall keep
information related to the non-compliance until found compliant or for the
retention period specified above, whichever is longer.

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaints
1.4. Additional Compliance Information
None

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

2.
R#
R1

Violation Severity Levels
Lower VSL

N/A

Moderate VSL

High VSL

Severe VSL

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas that may
form islands.

The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of historical
events and system studies, to
select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas
and Regional Entity areas, that
may form islands.

The Planning Coordinator failed
to develop and document
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas and
Regional Entity areas, that may
form islands.

The Planning Coordinator
identified an island(s) to serve

The Planning Coordinator
identified an island(s) to serve

OR
The Planning Coordinator
developed and documented
criteria but failed to include
the consideration of system
studies, to select portions of
the BES, including
interconnected portions of
the BES in adjacent Planning
Coordinator areas and
Regional Entity areas, that
may form islands.
R2

N/A

The Planning Coordinator
identified an island(s) to

Page 10 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

serve as a basis for designing
its UFLS program but failed to
include one (1) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its
UFLS program but failed to
include two (2) of the Parts as
specified in Requirement R2,
Parts 2.1, 2.2, or 2.3.

as a basis for designing its UFLS
program but failed to include all
of the Parts as specified in
Requirement R2, Parts 2.1, 2.2,
or 2.3.
OR
The Planning Coordinator failed
to identify any island(s) to serve
as a basis for designing its UFLS
program.

R3

N/A

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation
by UFLS entities within its
area where imbalance = [(load
— actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet one (1) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of
underfrequency conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation
by UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified island(s).,
but failed to meet two (2) of
the performance
characteristic in Requirement
R3, Parts 3.1, 3.2, or 3.3 in
simulations of underfrequency
conditions.

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area
where imbalance = [(load —
actual generation output) /
(load)], of up to 25 percent
within the identified
island(s).,but failed to meet all
the performance characteristic
in Requirement R3, Parts 3.1,
3.2, and 3.3 in simulations of
underfrequency conditions.
OR
The Planning Coordinator failed
to develop a UFLS program
Page 11 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
including notification of and a
schedule for implementation by
UFLS entities within its area

R4

The Planning Coordinator
conducted and documented a
UFLS assessment at least
once every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics
in Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
one (1) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
two (2) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that
determined through dynamic
simulation whether the UFLS
program design met the
performance characteristics in
Requirement R3 for each
island identified in
Requirement R2 but the
simulation failed to include
three (3) of the items as
specified in Requirement R4,
Parts 4.1 through 4.7.

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
R3 but simulation failed to
include four (4) or more of the
items as specified in
Requirement R4, Parts 4.1
through 4.7.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
R3 for each island identified in
Requirement R2

Page 12 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R5

N/A

N/A

N/A

The Planning Coordinator, whose
area or portions of whose area is
part of an island identified by it
or another Planning Coordinator
which includes multiple Planning
Coordinator areas or portions of
those areas, failed to coordinate
its UFLS program design through
one of the manners described in
Requirement R5.

R6

N/A

N/A

N/A

The Planning Coordinator failed
to maintain a UFLS database for
use in event analyses and
assessments of the UFLS
program at least once each
calendar year, with no more
than 15 months between
maintenance activities.

R7

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 30 calendar days
and up to and including 40
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 40 calendar days
but less than and including 50
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 50 calendar days
but less than and including 60
calendar days following the
request.

The Planning Coordinator
provided its UFLS database to
other Planning Coordinators
more than 60 calendar days
following the request.
OR

Page 13 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
The Planning Coordinator failed
to provide its UFLS database to
other Planning Coordinators.

R8

The UFLS entity provided data
to its Planning Coordinator(s)
less than or equal to 10
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 10 calendar days
but less than or equal to 15
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data
to its Planning Coordinator(s)
more than 15 calendar days
but less than or equal to 20
calendar days following the
schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided data to
its Planning Coordinator(s) more
than 20 calendar days following
the schedule specified by the
Planning Coordinator(s) to
support maintenance of each
Planning Coordinator’s UFLS
database.

The UFLS entity provided less
than 90% but more than (and
including) 85% of automatic
tripping of Load in accordance
with the UFLS program design

The UFLS entity provided less
than 85% of automatic tripping
of Load in accordance with the
UFLS program design and
schedule for implementation,

OR
The UFLS entity provided data
to its Planning Coordinator(s)
but the data was not
according to the format
specified by the Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.
R9

The UFLS entity provided less
than 100% but more than
(and including) 95% of
automatic tripping of Load in
accordance with the UFLS

The UFLS entity provided less
than 95% but more than (and
including) 90% of automatic
tripping of Load in accordance
with the UFLS program design

OR
The UFLS entity failed to provide
data to its Planning
Coordinator(s) to support
maintenance of each Planning
Coordinator’s UFLS database.

Page 14 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

program design and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which
it owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) area in which it
owns assets.

including any Corrective Action
Plan, as determined by the
Planning Coordinator(s) area in
which it owns assets.

R10

The Transmission Owner
provided less than 100% but
more than (and including)
95% automatic switching of
its existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 95% but
more than (and including)
90% automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the
UFLS program and schedule
for implementation, including
any Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission
Owner owns transmission.

The Transmission Owner
provided less than 90% but
more than (and including) 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and
reactors to control overvoltage if required by the UFLS
program and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each
Planning Coordinator area in
which the Transmission Owner
owns transmission.

The Transmission Owner
provided less than 85%
automatic switching of its
existing capacitor banks,
Transmission Lines, and reactors
to control over-voltage if
required by the UFLS program
and schedule for
implementation, including any
Corrective Action Plan, as
determined by the Planning
Coordinator(s) in each Planning
Coordinator area in which the
Transmission Owner owns
transmission.

R11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below
the initializing set points of the

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,

Page 15 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than one year
but less than or equal to 13
months of actuation.

the UFLS program, conducted
and documented an
assessment of the event and
evaluated the parts as
specified in Requirement R11,
Parts 11.1 and 11.2 within a
time greater than 13 months
but less than or equal to 14
months of actuation.

UFLS program, conducted and
documented an assessment of
the event and evaluated the
parts as specified in
Requirement R11, Parts 11.1
and 11.2 within a time greater
than 14 months but less than
or equal to 15 months of
actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the
initializing set points of the
UFLS program, conducted and
documented an assessment of
the event within one year of
event actuation but failed to
evaluate one (1) of the Parts
as specified in Requirement
R11, Parts11.1 or 11.2.

Severe VSL
conducted and documented an
assessment of the event and
evaluated the parts as specified
in Requirement R11, Parts 11.1
and 11.2 within a time greater
than 15 months of actuation.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to conduct and document
an assessment of the event and
evaluate the Parts as specified in
Requirement R11, Parts 11.1 and
11.2.
OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
conducted and documented an
assessment of the event within
one year of event actuation but
failed to evaluate all of the Parts

Page 16 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
as specified in Requirement R11,
Parts 11.1 and 11.2.

R12

R13

N/A

N/A

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than two
years but less than or equal to
25 months of event actuation.

The Planning Coordinator, in
which UFLS program
deficiencies were identified
per Requirement R11,
conducted and documented a
UFLS design assessment to
consider the identified
deficiencies greater than 25
months but less than or equal
to 26 months of event
actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, conducted and documented
a UFLS design assessment to
consider the identified
deficiencies greater than 26
months of event actuation.

N/A

N/A

The Planning Coordinator, in
whose area a BES islanding event
occurred that also included the
area(s) or portions of area(s) of
other Planning Coordinator(s) in
the same islanding event and
that resulted in system
frequency excursions below the
initializing set points of the UFLS

OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
R11, failed to conduct and
document a UFLS design
assessment to consider the
identified deficiencies.

Page 17 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL
program, failed to coordinate its
UFLS event assessment with all
other Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event in
one of the manners described in
Requirement R13

R14

N/A

N/A

N/A

The Planning Coordinator failed
to respond to written comments
submitted by UFLS entities and
Transmission Owners within its
Planning Coordinator area
following a comment period and
before finalizing its UFLS
program, indicating in the
written response to comments
whether changes were made or
reasons why changes were not
made to the items in Parts 14.1
through 14.3.

R15

N/A

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance
characteristics in Requirement

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program
did not meet the performance
characteristics in Requirement

The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance
characteristics in Requirement
Page 18 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period of
up to 1 month.

R3, and developed a
Corrective Action Plan and a
schedule for implementation
by the UFLS entities within its
area, but exceeded the
permissible time frame for
development by a period
greater than 1 month but not
more than 2 months.

R3, but failed to develop a
Corrective Action Plan and a
schedule for implementation by
the UFLS entities within its area.
OR
The Planning Coordinator
determined, through a UFLS
design assessment performed
under Requirement R4, R5, or
R12, that the UFLS program did
not meet the performance
characteristics in Requirement
R3, and developed a Corrective
Action Plan and a schedule for
implementation by the UFLS
entities within its area, but
exceeded the permissible time
frame for development by a
period greater than 2 months.

Page 19 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D. Regional Variances
D.A. Regional Variance for the Quebec Interconnection
The following Interconnection-wide variance shall be applicable in the Quebec
Interconnection and replaces, in their entirety, Requirements R3 and R4 and the
violation severity levels associated with Requirements R3 and R4.
Rationale for Requirement D.A.3:
There are two modifications for requirement D.A.3 :
1. 25% Generation Deficiency : Since the Quebec Interconnection has no potential
viable BES Island in underfrequency conditions, the largest generation deficiency
scenarios are limited to extreme contingencies not already covered by RAS.
Based on Hydro-Québec TransÉnergie Transmission Planning requirements, the
stability of the network shall be maintained for extreme contingencies using a case
representing internal transfers not expected to be exceeded 25% of the time.
The Hydro-Québec TransÉnergie defense plan to cover these extreme contingencies
includes two RAS (RPTC- generation rejection and remote load shedding and TDST a centralized UVLS) and the UFLS.
2. Frequency performance curve (attachment 1A) : Specific cases where a small
generation deficiency using a peak case scenario with the minimum requirement of
spinning reserve can lead to an acceptable frequency deviation in the Quebec
Interconnection while stabilizing between the PRC-006-2 requirement (59.3 Hz) and
the UFLS anti-stall threshold (59.0 Hz).
An increase of the anti-stall threshold to 59.3 Hz would correct this situation but would
cause frequent load shedding of customers without any gain of system reliability.
Therefore, it is preferable to lower the steady state frequency minimum value to 59.0
Hz.
The delay in the performance characteristics curve is harmonized between D.A.3 and
R.3 to 60 seconds.
Rationale for Requirements D.A.3.3. and D.A.4:
The Quebec Interconnection has its own definition of BES. In Quebec, the vast
majority of BES generating plants/facilities are not directly connected to the BES. For
simulations to take into account sufficient generating resources D.A.3.3 and D.A.4
need simply refer to BES generators, plants or facilities since these are listed in a
Registry approved by Québec’s Regulatory Body (Régie de l’Énergie).

D.A.3. Each Planning Coordinator shall develop a UFLS program, including notification
of and a schedule for implementation by UFLS entities within its area, that

Page 20 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
meets the following performance characteristics in simulations of
underfrequency conditions resulting from each of these extreme events:
•

Loss of the entire capability of a generating station.

•

Loss of all transmission circuits emanating from a generating
station, switching station, substation or dc terminal.

•

Loss of all transmission circuits on a common right-of-way.

•

Three-phase fault with failure of a circuit breaker to operate and
correct operation of a breaker failure protection system and its
associated breakers.

•

Three-phase fault on a circuit breaker, with normal fault clearing.

•

The operation or partial operation of a RAS for an event or
condition for which it was not intended to operate.

[VRF: High][Time Horizon: Long-term Planning]
D.A.3.1.

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-3 4 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-3 4 - Attachment 1A, either for 60
seconds or until a steady-state condition between 59.0 Hz and 60.7
Hz is reached, and

D.A.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than
two seconds cumulatively per simulated event, and shall not exceed
1.10 per unit for longer than 45 seconds cumulatively per simulated
event at each Quebec BES generator bus and associated generator
step-up transformer high-side bus

M.D.A.3. Each Planning Coordinator shall have evidence such as reports,
memorandums, e-mails, program plans, or other documentation of its UFLS
program, including the notification of the UFLS entities of implementation
schedule, that meet the criteria in Requirement D.A.3 Parts D.A.3.1 through
D.A.3.3.
D.A.4. Each Planning Coordinator shall conduct and document a UFLS design
assessment at least once every five years that determines through dynamic
simulation whether the UFLS program design meets the performance
characteristics in Requirement D.A.3 for each island identified in Requirement
Page 21 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
R2. The simulation shall model each of the following; [VRF: High][Time
Horizon: Long-term Planning]
D.A.4.1

Underfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip above the Generator
Underfrequency Trip Modeling curve in PRC-006-3 4 - Attachment
1A, and

D.A.4.2

Overfrequency trip settings of individual generating units that are
part of Quebec BES plants/facilities that trip below the Generator
Overfrequency Trip Modeling curve in PRC-006-3 4 - Attachment
1A, and

D.A.4.3

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.A.4. Each Planning Coordinator shall have dated evidence such as reports,
dynamic simulation models and results, or other dated documentation of its
UFLS design assessment that demonstrates it meets Requirement D.A.4
Parts D.A.4.1 through D.A.4.3.

Page 22 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#
DA3

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
developed a UFLS program,
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet two (2) of the
performance characteristic in
Parts D.A.3.1, D.A.3.2, or D.A.3.3
in simulations of underfrequency
conditions

Severe VSL
The Planning Coordinator
developed a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Parts D.A.3.1, D.A.3.2, and
D.A.3.3 in simulations of
underfrequency conditions
OR
The Planning Coordinator failed
to develop a UFLS program
including notification of and a
schedule for implementation by
UFLS entities within its area.

DA4

N/A

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed
to include one (1) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include two (2) of the items as

The Planning Coordinator
conducted and documented a
UFLS assessment at least once
every five years that determined
through dynamic simulation
whether the UFLS program
design met the performance
characteristics in Requirement
D.A.3 but the simulation failed to
include all of the items as
Page 23 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL
specified in Parts D.A.4.1,
D.A.4.2 or D.A.4.3.

High VSL

Severe VSL

specified in Parts D.A.4.1, D.A.4.2
or D.A.4.3.

specified in Parts D.A.4.1, D.A.4.2
and D.A.4.3.
OR
The Planning Coordinator failed
to conduct and document a UFLS
assessment at least once every
five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.A.3

Page 24 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D.B.

Regional Variance for the Western Electricity Coordinating Council
The following Interconnection-wide variance shall be applicable in the Western
Electricity Coordinating Council (WECC) and replaces, in their entirety, Requirements R1,
R2, R3, R4, R5, R11, R12, and R13.
D.B.1. Each Planning Coordinator shall participate in a joint regional review with the
other Planning Coordinators in the WECC Regional Entity area that develops and
documents criteria, including consideration of historical events and system
studies, to select portions of the Bulk Electric System (BES) that may form
islands. [VRF: Medium][Time Horizon: Long-term Planning]
M.D.B.1. Each Planning Coordinator shall have evidence such as reports, or other
documentation of its criteria, developed as part of the joint regional review
with other Planning Coordinators in the WECC Regional Entity area to select
portions of the Bulk Electric System that may form islands including how system
studies and historical events were considered to develop the criteria per
Requirement D.B.1.
D.B.2. Each Planning Coordinator shall identify one or more islands from the regional
review (per D.B.1) to serve as a basis for designing a region-wide coordinated
UFLS program including: [VRF: Medium][Time Horizon: Long-term Planning]
D.B.2.1. Those islands selected by applying the criteria in Requirement D.B.1,
and
D.B.2.2. Any portions of the BES designed to detach from the Interconnection
(planned islands) as a result of the operation of a relay scheme or
Special Protection System.
M.D.B.2. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, or other documentation supporting its identification of an island(s),
from the regional review (per D.B.1), as a basis for designing a region-wide
coordinated UFLS program that meet the criteria in Requirement D.B.2 Parts
D.B.2.1 and D.B.2.2.
D.B.3. Each Planning Coordinator shall adopt a UFLS program, coordinated across the
WECC Regional Entity area, including notification of and a schedule for
implementation by UFLS entities within its area, that meets the following
performance characteristics in simulations of underfrequency conditions
resulting from an imbalance scenario, where an imbalance = [(load — actual
generation output) / (load)], of up to 25 percent within the identified island(s).
[VRF: High][Time Horizon: Long-term Planning]
D.B.3.1.

Frequency shall remain above the Underfrequency Performance
Characteristic curve in PRC-006-3 4 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and
Page 25 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D.B.3.2.

Frequency shall remain below the Overfrequency Performance
Characteristic curve in PRC-006-3 4 - Attachment 1, either for 60
seconds or until a steady-state condition between 59.3 Hz and 60.7
Hz is reached, and

D.B.3.3.

Volts per Hz (V/Hz) shall not exceed 1.18 per unit for longer than two
seconds cumulatively per simulated event, and shall not exceed 1.10
per unit for longer than 45 seconds cumulatively per simulated event
at each generator bus and generator step-up transformer high-side
bus associated with each of the following:
D.B.3.3.1. Individual generating units greater than 20 MVA (gross
nameplate rating) directly connected to the BES
D.B.3.3.2. Generating plants/facilities greater than 75 MVA (gross
aggregate nameplate rating) directly connected to the
BES
D.B.3.3.3. Facilities consisting of one or more units connected to
the BES at a common bus with total generation above 75
MVA gross nameplate rating.

M.D.B.3. Each Planning Coordinator shall have evidence such as reports, memorandums,
e-mails, program plans, or other documentation of its adoption of a UFLS
program, coordinated across the WECC Regional Entity area, including the
notification of the UFLS entities of implementation schedule, that meet the
criteria in Requirement D.B.3 Parts D.B.3.1 through D.B.3.3.
D.B.4. Each Planning Coordinator shall participate in and document a coordinated
UFLS design assessment with the other Planning Coordinators in the WECC
Regional Entity area at least once every five years that determines through
dynamic simulation whether the UFLS program design meets the performance
characteristics in Requirement D.B.3 for each island identified in Requirement
D.B.2. The simulation shall model each of the following: [VRF: High][Time
Horizon: Long-term Planning]
D.B.4.1.

Underfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip above the Generator Underfrequency Trip Modeling curve
in PRC-006-3 4 - Attachment 1.

D.B.4.2.

Underfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip above the Generator Underfrequency Trip
Modeling curve in PRC-006-3 4 - Attachment 1.

D.B.4.3.

Underfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
Page 26 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
above 75 MVA (gross nameplate rating) that trip above the
Generator Underfrequency Trip Modeling curve in PRC-006-3 4 Attachment 1.
D.B.4.4.

Overfrequency trip settings of individual generating units greater
than 20 MVA (gross nameplate rating) directly connected to the BES
that trip below the Generator Overfrequency Trip Modeling curve in
PRC-006-3 4 — Attachment 1.

D.B.4.5.

Overfrequency trip settings of generating plants/facilities greater
than 75 MVA (gross aggregate nameplate rating) directly connected
to the BES that trip below the Generator Overfrequency Trip
Modeling curve in PRC-006-3 4 — Attachment 1.

D.B.4.6.

Overfrequency trip settings of any facility consisting of one or more
units connected to the BES at a common bus with total generation
above 75 MVA (gross nameplate rating) that trip below the
Generator Overfrequency Trip Modeling curve in PRC-006-3 4 —
Attachment 1.

D.B.4.7.

Any automatic Load restoration that impacts frequency stabilization
and operates within the duration of the simulations run for the
assessment.

M.D.B.4. Each Planning Coordinator shall have dated evidence such as reports, dynamic
simulation models and results, or other dated documentation of its participation
in a coordinated UFLS design assessment with the other Planning Coordinators in
the WECC Regional Entity area that demonstrates it meets Requirement D.B.4
Parts D.B.4.1 through D.B.4.7.
D.B.11.

Each Planning Coordinator, in whose area a BES islanding event results in system
frequency excursions below the initializing set points of the UFLS program, shall
participate in and document a coordinated event assessment with all affected
Planning Coordinators to conduct and document an assessment of the event
within one year of event actuation to evaluate: [VRF: Medium][Time Horizon:
Operations Assessment]
D.B.11.1. The performance of the UFLS equipment,
D.B.11.2 The effectiveness of the UFLS program

M.D.B.11. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a coordinated event assessment of the performance of the UFLS
equipment and the effectiveness of the UFLS program per Requirement D.B.11.

Page 27 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D.B.12.

Each Planning Coordinator, in whose islanding event assessment (per D.B.11)
UFLS program deficiencies are identified, shall participate in and document a
coordinated UFLS design assessment of the UFLS program with the other
Planning Coordinators in the WECC Regional Entity area to consider the
identified deficiencies within two years of event actuation. [VRF: Medium][Time
Horizon: Operations Assessment]

M.D.B.12. Each Planning Coordinator shall have dated evidence such as reports, data
gathered from an historical event, or other dated documentation to show that it
participated in a UFLS design assessment per Requirements D.B.12 and D.B.4 if
UFLS program deficiencies are identified in D.B.11.

Page 28 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#
D.B.1

Lower VSL
N/A

Moderate VSL

High VSL

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical
events, to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of historical events
and system studies, to select
portions of the BES, including
interconnected portions of the
BES in adjacent Planning
Coordinator areas, that may form
islands

OR

Severe VSL
The Planning Coordinator failed
to participate in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria to select portions of the
BES, including interconnected
portions of the BES in adjacent
Planning Coordinator areas that
may form islands

The Planning Coordinator
participated in a joint regional
review with the other Planning
Coordinators in the WECC
Regional Entity area that
developed and documented
criteria but failed to include the
consideration of system studies,
to select portions of the BES,
including interconnected
portions of the BES in adjacent
Planning Coordinator areas, that
may form islands
Page 29 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#
D.B.2

Lower VSL

Moderate VSL

High VSL

N/A
N/A

The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include one
(1) of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2

Severe VSL
The Planning Coordinator
identified an island(s) from the
regional review to serve as a
basis for designing its UFLS
program but failed to include all
of the parts as specified in
Requirement D.B.2, Parts D.B.2.1
or D.B.2.2
OR
The Planning Coordinator failed
to identify any island(s) from the
regional review to serve as a
basis for designing its UFLS
program.

D.B.3

N/A

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet one (1) of the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, or D.B.3.3 in

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that included
notification of and a schedule for
implementation by UFLS entities
within its area, but failed to meet
two (2) of the performance
characteristic in Requirement
D.B.3, Parts D.B.3.1, D.B.3.2, or
D.B.3.3 in simulations of
underfrequency conditions

The Planning Coordinator
adopted a UFLS program,
coordinated across the WECC
Regional Entity area that
included notification of and a
schedule for implementation by
UFLS entities within its area, but
failed to meet all the
performance characteristic in
Requirement D.B.3, Parts
D.B.3.1, D.B.3.2, and D.B.3.3 in

Page 30 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

simulations of underfrequency
conditions

Severe VSL
simulations of underfrequency
conditions
OR
The Planning Coordinator failed
to adopt a UFLS program,
coordinated across the WECC
Regional Entity area, including
notification of and a schedule for
implementation by UFLS entities
within its area.

D.B.4

The Planning Coordinator
participated in and
documented a coordinated
UFLS assessment with the other
Planning Coordinators in the
WECC Regional Entity area at
least once every five years that
determines through dynamic
simulation whether the UFLS
program design meets the
performance characteristics in
Requirement D.B.3 for each
island identified in Requirement
D.B.2 but the simulation failed
to include one (1) of the items
as specified in Requirement

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include two
(2) of the items as specified in

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include three
(3) of the items as specified in

The Planning Coordinator
participated in and documented
a coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2 but the
simulation failed to include four
(4) or more of the items as

Page 31 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL
D.B.4, Parts D.B.4.1 through
D.B.4.7.

Moderate VSL

High VSL

Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

Requirement D.B.4, Parts D.B.4.1
through D.B.4.7.

Severe VSL
specified in Requirement D.B.4,
Parts D.B.4.1 through D.B.4.7.
OR
The Planning Coordinator failed
to participate in and document a
coordinated UFLS assessment
with the other Planning
Coordinators in the WECC
Regional Entity area at least once
every five years that determines
through dynamic simulation
whether the UFLS program
design meets the performance
characteristics in Requirement
D.B.3 for each island identified in
Requirement D.B.2

D.B.11

The Planning Coordinator, in
whose area a BES islanding
event resulting in system
frequency excursions below the
initializing set points of the
UFLS program, participated in
and documented a coordinated
event assessment with all
Planning Coordinators whose
areas or portions of whose
areas were also included in the

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and

The Planning Coordinator, in
whose area a BES islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event and
Page 32 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

same islanding event and
evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than one year but
less than or equal to 13 months
of actuation.

evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 13 months but
less than or equal to 14 months
of actuation.

evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 14 months but
less than or equal to 15 months
of actuation.

evaluated the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2 within a
time greater than 15 months of
actuation.

OR

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
failed to participate in and
document a coordinated event
assessment with all Planning
Coordinators whose areas or
portion of whose areas were also
included in the same island event
and evaluate the parts as
specified in Requirement D.B.11,
Parts D.B.11.1 and D.B.11.2.

The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event
within one year of event
actuation but failed to evaluate
one (1) of the parts as specified
in Requirement D.B.11, Parts
D.B.11.1 or D.B.11.2.

Severe VSL

OR

OR
The Planning Coordinator, in
whose area an islanding event
resulting in system frequency
excursions below the initializing
set points of the UFLS program,
participated in and documented
Page 33 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
a coordinated event assessment
with all Planning Coordinators
whose areas or portions of
whose areas were also included
in the same islanding event
within one year of event
actuation but failed to evaluate
all of the parts as specified in
Requirement D.B.11, Parts
D.B.11.1 and D.B.11.2.

D.B.12

N/A

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than two
years but less than or equal to 25
months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 25
months but less than or equal to
26 months of event actuation.

The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, participated in and
documented a coordinated UFLS
design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies in greater than 26
months of event actuation.
OR
The Planning Coordinator, in
which UFLS program deficiencies
were identified per Requirement
D.B.11, failed to participate in
Page 34 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
D#

Lower VSL

Moderate VSL

High VSL

Severe VSL
and document a coordinated
UFLS design assessment of the
coordinated UFLS program with
the other Planning Coordinators
in the WECC Regional Entity area
to consider the identified
deficiencies

Page 35 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
E. Associated Documents
Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

May 25, 2010

Completed revision, merging and
updating PRC-006-0, PRC-007-0 and
PRC-009-0.

1

November 4, 2010

Adopted by the Board of Trustees

1

May 7, 2012

FERC Order issued approving PRC006-1 (approval becomes effective
July 10, 2012)

1

November 9, 2012

2

November 13, 2014

FERC Letter Order issued accepting
the modification of the VRF in R5
from (Medium to High) and the
modification of the VSL language in
R8.
Adopted by the Board of Trustees

Revisions made under
Project 2008-02:
Undervoltage Load
Shedding (UVLS) &
Underfrequency Load
Shedding (UFLS) to address
directive issued in FERC
Order No. 763.
Revisions to existing
Requirement R9 and
R10 and addition of
new Requirement
R15.

3

August 10, 2017

Adopted by the NERC Board of
Trustees

4

February 6, 2020

Adopted by NERC Board of Trustees

Revisions to the Regional
Variance for the Quebec
Interconnection.
Revisions under Project
2017-07

Page 36 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

PRC-006-3 4 – Attachment 1
Underfrequency Load Shedding Program
Design Performance and Modeling Curves for
Requirements R3 Parts 3.1-3.2 and R4 Parts 4.1-4.6
63

Overfrequency Trip Settings
Must Be Modeled for Generators
That Trip Below the Generator
Overfrequency Trip Modeling
Curve

62

Simulated Frequency Must
Remain Between the
Overfrequency and
Underfrequency Performance
Characteristic Curves

60

59

58

Underfrequency Trip Settings
Must Be Modeled for Generators
That Trip Above the Generator
Underfrequency Trip Modeling
Curve

57
1

0.1

Time (sec)

10

100

Generator Overfrequency Trip Modeling (Requirement R4 Parts 4.4-4.6)
Overfrequency Performance Characteristic (Requirement R3 Part 3.2)
Underfrequency Performance Characteristic (Requirement R3 Part 3.1)
Generator Underfrequency Trip Modeling (Requirement R4 Parts 4.1-4.3)

Curve Definitions
Generator Overfrequency Trip Modeling

Overfrequency Performance Characteristic

t≤2s

t≤4s

t>2s

4 s < t ≤ 30 s

t > 30 s

Page 37 of 40

Frequency (Hz)

61

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding
f = 62.2
Hz

f = -0.686log(t) + 62.41
Hz

f = 61.8
Hz

f = -0.686log(t) + 62.21
Hz

f = 60.7
Hz

Generator Underfrequency Trip
Modeling

Underfrequency Performance Characteristic

t≤2s

t>2s

t≤2s

2 s < t ≤ 60 s

t > 60 s

f = 57.8
Hz

f = 0.575log(t) + 57.63
Hz

f = 58.0
Hz

f = 0.575log(t) + 57.83
Hz

f = 59.3
Hz

Page 38 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

Page 39 of 40

Standard PRC-006-3 4 — Automatic Underfrequency Load Shedding

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 R9:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a Planning Coordinator (PC)
assessment. The revised language adds clarity by requiring that each UFLS entity follow the
UFLS program, including any Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R10:
The “Corrective Action Plan” language was added in response to the FERC directive from Order
No. 763, which raised concern that the standard failed to specify how soon an entity would
need to implement corrections after a deficiency is identified by a PC assessment. The revised
language adds clarity by requiring that each UFLS entity follow the UFLS program, including any
Corrective Action Plan, developed by the PC.
Also, to achieve consistency of terminology throughout this standard, the word “application”
was replaced with “implementation.” (See Requirements R3, R14 and R15)
Rationale for R15:
Requirement R15 was added in response to the directive from FERC Order No. 763, which
raised concern that the standard failed to specify how soon an entity would need to implement
corrections after a deficiency is identified by a PC assessment. Requirement R15 addresses the
FERC directive by making explicit that if deficiencies are identified as a result of an assessment,
the PC shall develop a Corrective Action Plan and schedule for implementation by the UFLS
entities.
A “Corrective Action Plan” is defined in the NERC Glossary of Terms as, “a list of actions and an
associated timetable for implementation to remedy a specific problem.” Thus, the Corrective
Action Plan developed by the PC will identify the specific timeframe for an entity to implement
corrections to remedy any deficiencies identified by the PC as a result of an assessment.

Page 40 of 40

TOP-003-4 — Operational Reliability Data

A. Introduction
1.

Title: Operational Reliability Data

2.

Number: TOP-003-4

3.

Purpose: To ensure that the Transmission Operator and Balancing Authority have
data needed to fulfill their operational and planning responsibilities.

4.

Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Generator Owner
4.4. Generator Operator
4.5. Transmission Owner
4.6. Distribution Provider

5.

Effective Date:
See Implementation Plan.

B. Requirements and Measures
R1. Each Transmission Operator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include, but not be limited to:
[Violation Risk Factor: Low] [Time Horizon: Operations Planning]
1.1.

A list of data and information needed by the Transmission Operator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data as
deemed necessary by the Transmission Operator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

M1. Each Transmission Operator shall make available its dated, current, in force
documented specification for data.
R2.

Each Balancing Authority shall maintain a documented specification for the data
necessary for it to perform its analysis functions and Real-time monitoring. The data
specification shall include, but not be limited to: [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]

Draft 2 of TOP-003-4
January 2020

Page 1 of 10

TOP-003-4 — Operational Reliability Data

2.1.

A list of data and information needed by the Balancing Authority to support
its analysis functions and Real-time monitoring.

2.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

2.3.

A periodicity for providing data.

2.4.

The deadline by which the respondent is to provide the indicated data.

M2. Each Balancing Authority shall make available its dated, current, in force documented
specification for data.
R3. Each Transmission Operator shall distribute its data specification to entities that have
data required by the Transmission Operator’s Operational Planning Analyses, Realtime monitoring, and Real-time Assessment. [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]
M3. Each Transmission Operator shall make available evidence that it has distributed its
data specification to entities that have data required by the Transmission Operator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments.
Such evidence could include but is not limited to web postings with an electronic
notice of the posting, dated operator logs, voice recordings, postal receipts showing
the recipient, date and contents, or e-mail records.
R4. Each Balancing Authority shall distribute its data specification to entities that have
data required by the Balancing Authority’s analysis functions and Real-time
monitoring. [Violation Risk Factor: Low] [Time Horizon: Operations Planning]
M4. Each Balancing Authority shall make available evidence that it has distributed its data
specification to entities that have data required by the Balancing Authority’s analysis
functions and Real-time monitoring. Such evidence could include but is not limited to
web postings with an electronic notice of the posting, dated operator logs, voice
recordings, postal receipts showing the recipient, or e-mail records.
R5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Owner, and Distribution Provider receiving a data
specification in Requirement R3 or R4 shall satisfy the obligations of the documented
specifications using: [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning, Same-Day Operations, Real-time Operations]
5.1. A mutually agreeable format
5.2. A mutually agreeable process for resolving data conflicts
5.3. A mutually agreeable security protocol
M5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Transmission Owner, and Distribution Provider receiving a data specification
in Requirement R3 or R4 shall make available evidence that it has satisfied the
obligations of the documented specifications. Such evidence could include, but is not
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TOP-003-4 — Operational Reliability Data

limited to, electronic or hard copies of data transmittals or attestations of receiving
entities.
C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Process
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Assessment Processes
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated reliability standard.
1.3. Data 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 responsible entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
Each Transmission Operator shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments in accordance with
Requirement R1 and Measurement M1 as well as any documents in force since
the last compliance audit.
Each Balancing Authority shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its analysis functions and
Real-time monitoring in accordance with Requirement R2 and Measurement M2
as well as any documents in force since the last compliance audit.
Each Transmission Operator shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the
Transmission Operator’s Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments in accordance with Requirement R3 and
Measurement M3.

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TOP-003-4 — Operational Reliability Data

Each Balancing Authority shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the
Balancing Authority’s analysis functions and Real-time monitoring in accordance
with Requirement R4 and Measurement M4.
Each Balancing Authority, Generator Owner, Generator Operator, Transmission
Operator, Transmission Owner, and Distribution Provider receiving a data
specification in Requirement R3 or R4 shall retain evidence for the most recent
90-calendar days that it has satisfied the obligations of the documented
specifications in accordance with Requirement R5 and Measurement M5.
If a responsible entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved or the time
period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.

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TOP-003-4 — Operational Reliability Data

Table of Compliance Elements
R#

R1

Time Horizon

Operations
Planning

Draft 2 of TOP-003-4
January 2020

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Transmission
Operator did not
include one of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include three of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include four of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.
OR,
The Transmission
Operator did not have
a documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

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TOP-003-4 — Operational Reliability Data

R#

R2

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Balancing
Authority did not
include one of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include two of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include three of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include four of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.
OR,
The Balancing
Authority did not
have a documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

For the Requirement R3 and R4 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to
the left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity
has just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R3

Operations
Planning

Draft 2 of TOP-003-4
January 2020

Low

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

Page 6 of 10

TOP-003-4 — Operational Reliability Data

R#

R4

Time Horizon

Operations
Planning

Draft 2 of TOP-003-4
January 2020

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to two
entities, or more than
5% and less than or
equal to10% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to three
entities, or more than
10% and less than or
equal to 15% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Balancing
Authority did not
distribute its data
specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to two
entities, or more than
5% and less than or
equal to 10% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to three
entities, or more than
10% and less than or
equal to 15% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

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TOP-003-4 — Operational Reliability Data

R#

R5

Time Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

Draft 2 of TOP-003-4
January 2020

Violation Severity Levels

VRF

Medium

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible
entity receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet one of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet two of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet three of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
did not satisfy the
obligations of the
documented
specifications for
data.

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TOP-003-4 — Guidelines and Technical Basis

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

0

April 1, 2005

0

August 8, 2005

Action

Effective Date
Removed “Proposed” from Effective
Date
Modified R1.2
Modified M1

1

Change Tracking

New
Errata
Revised

Replaced Levels of Non-compliance
with the Feb 28, BOT approved
Violation Severity Levels (VSLs)
1

October 17, 2008

Adopted by NERC Board of Trustees

1

March 17, 2011

Order issued by FERC approving TOP003-1 (approval effective 5/23/11)

2

May 6, 2012

Revised under Project 2007-03

Revised

2

May 9, 2012

Adopted by Board of Trustees

Revised

3

April 2014

Changes pursuant to Project 2014-03

Revised

3

November 13, 2014 Adopted by Board of Trustees

3

November 19, 2015 FERC approved TOP-003-3. Docket No.
RM15-16-000, Order No. 817
Adopted by Board of Trustees

4

Draft 2 of TOP-003-4
January 2020

Revisions under
Project 2014-03

Page 9 of 10

TOP-003-4 — Guidelines and Technical Basis

Guidelines and Technical Basis
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 Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to
result in an appropriate level of situational awareness. Some examples include: 1) analyzing
phase angles which may result in the implementation of an Operating Plan to adjust generation
or curtail transactions so that a Transmission facility may be returned to service, or 2)
evaluating the impact of a modified Contingency resulting from the status change of a Special
Protection Scheme from enabled/in-service to disabled/out-of-service.
Rationale for R1:
Changes to proposed Requirement R1, Part 1.1 are in response to issues raised in NOPR
paragraph 67 on the need for obtaining non-BES and external network data necessary for the
Transmission Operator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2 is in response to NOPR paragraph 78 on relay data. The
language has been moved from approved PRC-001-1.
Corresponding changes have been made to Requirement R2 for the Balancing Authority and to
proposed IRO-010-2, Requirement R1 for the Reliability Coordinator.
Rationale for R5:
Proposed Requirement R5, Part 5.3 is in response to NOPR paragraph 92 where concerns were
raised about data exchange through secured networks.

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TOP‐003‐4 — Operational Reliability Data 

A. Introduction
1.

Title: Operational Reliability Data 

2.

Number: TOP‐003‐4 

3.

Purpose: To ensure that the Transmission Operator and Balancing Authority have 
data needed to fulfill their operational and planning responsibilities. 

4.

Applicability: 

4.1. Transmission Operator 
4.2. Balancing Authority 
4.3. Generator Owner 
4.4. Generator Operator 
4.5. Transmission Owner 
4.6. Distribution Provider
5.

Effective Date:   
See Implementation Plan.  

B. Requirements and Measures
R1. Each Transmission Operator shall maintain a documented specification for the data 
necessary for it to perform its Operational Planning Analyses, Real‐time monitoring, 
and Real‐time Assessments.  The data specification shall include, but not be limited to: 
[Violation Risk Factor: Low] [Time Horizon: Operations Planning] 
1.1.

A list of data and information needed by the Transmission Operator to 
support its Operational Planning Analyses, Real‐time monitoring, and Real‐
time Assessments including non‐BES data and external network data as 
deemed necessary by the Transmission Operator.   

1.2.

Provisions for notification of current Protection System and Special Protection 
System status or degradation that impacts System reliability.  

1.3.

A periodicity for providing data. 

1.4.

The deadline by which the respondent is to provide the indicated data. 

M1. Each Transmission Operator shall make available its dated, current, in force 
documented specification for data.  

R2.

Each Balancing Authority shall maintain a documented specification for the data 
necessary for it to perform its analysis functions and Real‐time monitoring.  The data 
specification shall include, but not be limited to: [Violation Risk Factor: Low] [Time 
Horizon: Operations Planning] 

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TOP‐003‐4 — Operational Reliability Data 

2.1.

A list of data and information needed by the Balancing Authority to support 
its analysis functions and Real‐time monitoring.  

2.2.

Provisions for notification of current Protection System and Special Protection 
System status or degradation that impacts System reliability.  

2.3.

A periodicity for providing data.  

2.4.

The deadline by which the respondent is to provide the indicated data. 

M2. Each Balancing Authority shall make available its dated, current, in force documented 
specification for data.  
R3. Each Transmission Operator shall distribute its data specification to entities that have 
data required by the Transmission Operator’s Operational Planning Analyses, Real‐
time monitoring, and Real‐time Assessment.  [Violation Risk Factor: Low] [Time 
Horizon: Operations Planning] 
M3. Each Transmission Operator shall make available evidence that it has distributed its 
data specification to entities that have data required by the Transmission Operator’s 
Operational Planning Analyses, Real‐time monitoring, and Real‐time Assessments.  
Such evidence could include but is not limited to web postings with an electronic 
notice of the posting, dated operator logs, voice recordings, postal receipts showing 
the recipient, date and contents, or e‐mail records.  

R4. Each Balancing Authority shall distribute its data specification to entities that have 
data required by the Balancing Authority’s analysis functions and Real‐time 
monitoring.  [Violation Risk Factor: Low] [Time Horizon: Operations Planning]  
M4. Each Balancing Authority shall make available evidence that it has distributed its data 
specification to entities that have data required by the Balancing Authority’s analysis 
functions and Real‐time monitoring.  Such evidence could include but is not limited to 
web postings with an electronic notice of the posting, dated operator logs, voice 
recordings, postal receipts showing the recipient, or e‐mail records. 
R5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator 
Operator,  Transmission Owner, and Distribution Provider receiving a data 
specification in Requirement R3 or R4 shall satisfy the obligations of the documented 
specifications using: [Violation Risk Factor: Medium] [Time Horizon: Operations 
Planning, Same‐Day Operations, Real‐time Operations] 
5.1. A mutually agreeable format  
5.2. A mutually agreeable process for resolving data conflicts   
5.3. A mutually agreeable security protocol   
M5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator 
Operator, Transmission Owner, and Distribution Provider receiving a data specification 
in Requirement R3 or R4 shall make available evidence that it has satisfied the 
obligations of the documented specifications.  Such evidence could include, but is not 
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TOP‐003‐4 — Operational Reliability Data 

limited to, electronic or hard copies of data transmittals or attestations of receiving 
entities. 
C. Compliance
1.

Compliance Monitoring Process 
1.1. Compliance Monitoring Process 
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” 
(CEA) means NERC or the Regional Entity in their respective roles of monitoring 
and enforcing compliance with the NERC Reliability Standards. 
1.2. Compliance Monitoring and Assessment Processes 
 As defined in the NERC Rules of Procedure, “Compliance Monitoring and 
Assessment Processes” refers to the identification of the processes that will be 
used to evaluate data or information for the purpose of assessing performance 
or outcomes with the associated reliability standard. 

1.3. Data 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 responsible entity shall keep data or evidence to show compliance as 
identified below unless directed by its Compliance Enforcement Authority to 
retain specific evidence for a longer period of time as part of an investigation: 
Each Transmission Operator shall retain its dated, current, in force, documented 
specification for the data necessary for it to perform its Operational Planning 
Analyses, Real‐time monitoring, and Real‐time Assessments in accordance with 
Requirement R1 and Measurement M1 as well as any documents in force since 
the last compliance audit.  
Each Balancing Authority shall retain its dated, current, in force, documented 
specification for the data necessary for it to perform its analysis functions and 
Real‐time monitoring in accordance with Requirement R2 and Measurement M2 
as well as any documents in force since the last compliance audit. 
Each Transmission Operator shall retain evidence for three calendar years that it 
has distributed its data specification to entities that have data required by the 
Transmission Operator’s Operational Planning Analyses, Real‐time monitoring, 
and Real‐time Assessments in accordance with Requirement R3 and 
Measurement M3.   

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TOP‐003‐4 — Operational Reliability Data 

Each Balancing Authority shall retain evidence for three calendar years that it 
has distributed its data specification to entities that have data required by the 
Balancing Authority’s analysis functions and Real‐time monitoring in accordance 
with Requirement R4 and Measurement M4.   
Each Balancing Authority, Generator Owner, Generator Operator, Transmission 
Operator, Transmission Owner, and Distribution Provider receiving a data 
specification in Requirement R3 or R4 shall retain evidence for the most recent 
90‐calendar days that it has satisfied the obligations of the documented 
specifications in accordance with Requirement R5 and Measurement M5.   
If a responsible entity is found non‐compliant, it shall keep information related 
to the non‐compliance until mitigation is complete and approved or the time 
period specified above, whichever is longer.  
The Compliance Enforcement Authority shall keep the last audit records and all 
requested and submitted subsequent audit records. 
1.4. Additional Compliance Information 
None.

Draft 1 2 of TOP‐003‐4 
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TOP‐003‐4 — Operational Reliability Data 

Table of Compliance Elements
R # 

R1 

Time Horizon 

Operations 
Planning 

Draft 12 of TOP‐003‐4 
October 2019January 2020 

VRF 

Low 

Violation Severity Levels 
Lower VSL 

Moderate VSL 

High VSL 

Severe VSL 

The Transmission 
Operator did not 
include one of the 
parts (Part 1.1 
through Part 1.4) of 
the documented 
specification for the 
data necessary for it 
to perform its 
Operational Planning 
Analyses, Real‐time 
monitoring, and Real‐
time Assessments.    

The Transmission 
Operator did not 
include two of the 
parts (Part 1.1 
through Part 1.4) of 
the documented 
specification for the 
data necessary for it 
to perform its 
Operational Planning 
Analyses, Real‐time 
monitoring, and Real‐
time Assessments.  

The Transmission 
Operator did not 
include three of the 
parts (Part 1.1 
through Part 1.4) of 
the documented 
specification for the 
data necessary for it 
to perform its 
Operational Planning 
Analyses, Real‐time 
monitoring, and Real‐
time Assessments. 

The Transmission 
Operator did not 
include four of the 
parts (Part 1.1 
through Part 1.4) of 
the documented 
specification for the 
data necessary for it 
to perform its 
Operational Planning 
Analyses, Real‐time 
monitoring, and Real‐
time Assessments. 
OR,  
The Transmission 
Operator did not have 
a documented 
specification for the 
data necessary for it 
to perform its 
Operational Planning 
Analyses, Real‐time 
monitoring, and Real‐
time Assessments.  

Page 5 of 10 

TOP‐003‐4 — Operational Reliability Data 

R # 

R2 

Time Horizon 

Operations 
Planning 

VRF 

Low 

Violation Severity Levels 
Lower VSL 

Moderate VSL 

High VSL 

Severe VSL 

The Balancing 
Authority did not 
include one of the 
parts (Part 2.1 
through Part 2.4) of 
the documented 
specification for the 
data necessary for it 
to perform its analysis 
functions and Real‐
time monitoring. 

The Balancing 
Authority did not 
include two of the 
parts (Part 2.1 
through Part 2.4) of 
the documented 
specification for the 
data necessary for it 
to perform its analysis 
functions and Real‐
time monitoring. 

The Balancing 
Authority did not 
include three of the 
parts (Part 2.1 
through Part 2.4) of 
the documented 
specification for the 
data necessary for it 
to perform its analysis 
functions and Real‐
time monitoring. 

The Balancing 
Authority did not 
include four of the 
parts (Part 2.1 
through Part 2.4) of 
the documented 
specification for the 
data necessary for it 
to perform its analysis 
functions and Real‐
time monitoring. 
OR,  
The Balancing 
Authority did not 
have a documented 
specification for the 
data necessary for it 
to perform its analysis 
functions and Real‐
time monitoring. 

For the Requirement R3 and R4 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to 
the left until you find the situation that fits.  In this manner, the VSL will not be discriminatory by size of entity.  If a small entity 
has just one affected reliability entity to inform, the intent is that that situation would be a Severe violation. 
R3 

Operations 
Planning 

Draft 12 of TOP‐003‐4 
October 2019January 2020 

Low 

The Transmission 
Operator did not 
distribute its data 

The Transmission 
Operator did not 
distribute its data 

The Transmission 
Operator did not 
distribute its data 

The Transmission 
Operator did not 
distribute its data 

Page 6 of 10 

TOP‐003‐4 — Operational Reliability Data 

R # 

R4 

Time Horizon 

Operations 
Planning 

Draft 12 of TOP‐003‐4 
October 2019January 2020 

VRF 

Low 

Violation Severity Levels 
Lower VSL 

Moderate VSL 

High VSL 

Severe VSL 

specification to one 
entity, or 5% or less of 
the entities, 
whichever is greater, 
that have data 
required by the 
Transmission 
Operator’s 
Operational Planning 
Analyses, Real‐time 
monitoring, and Real‐
time Assessments. 

specification to two  
entities, or more than 
5% and less than or 
equal to10% of the 
reliability entities, 
whichever is greater, 
that have data 
required by the 
Transmission 
Operator’s 
Operational Planning 
Analyses, Real‐time 
monitoring, and Real‐
time Assessments. 

specification to three  
entities, or more than 
10% and less than or 
equal to 15% of the 
reliability entities, 
whichever is greater, 
that have data 
required by the 
Transmission 
Operator’s 
Operational Planning 
Analyses, Real‐time 
monitoring, and Real‐
time Assessments. 

specification to four 
or more entities, or 
more than 15% of the 
entities that have 
data required by the 
Transmission 
Operator’s 
Operational Planning 
Analyses, Real‐time 
monitoring, and Real‐
time Assessments. 

The Balancing 
Authority did not 
distribute its data 
specification to one 
entity, or 5% or less of 
the entities, 
whichever is greater, 
that have data 
required by the 
Balancing Authority’s 
analysis functions and 
Real‐time monitoring. 

The Balancing 
Authority did not 
distribute its data 
specification to two  
entities, or more than 
5% and less than or 
equal to 10% of the 
entities, whichever is 
greater, that have 
data required by the 
Balancing Authority’s 
analysis functions and 
Real‐time monitoring. 

The Balancing 
Authority did not 
distribute its data 
specification to three 
entities, or more than 
10% and less than or 
equal to 15% of the 
entities, whichever is 
greater, that have 
data required by the 
Balancing Authority’s 
analysis functions and 
Real‐time monitoring. 

The Balancing 
Authority did not 
distribute its data 
specification to four 
or more entities, or 
more than 15% of the 
entities that have 
data required by the 
Balancing Authority’s 
analysis functions and 
Real‐time monitoring. 

Page 7 of 10 

TOP‐003‐4 — Operational Reliability Data 

R # 

Time Horizon 

VRF 

Violation Severity Levels 
Lower VSL 

R5 

Moderate VSL 

Operations  Medium   The responsible 
The responsible entity 
Planning, 
entity receiving a data  receiving a data 
specification in 
Same‐Day 
specification in 
Operations, 
Requirement R3 or R4  Requirement R3 or R4 
satisfied the 
Real‐time 
satisfied the 
Operations 
obligations in the data  obligations in the data 
specification but did 
specification but did 
not meet one of the 
not meet two of the 
criteria shown in 
criteria shown in 
Requirement R5 
Requirement R5 
(Parts 5.1 – 5.3). 
(Parts 5.1 – 5.3). 

Draft 12 of TOP‐003‐4 
October 2019January 2020 

High VSL 

Severe VSL 

The responsible entity 
receiving a data 
specification in 
Requirement R3 or R4 
satisfied the 
obligations in the data 
specification but did 
not meet three of the 
criteria shown in 
Requirement R5 
(Parts 5.1 – 5.3). 

The responsible entity 
receiving a data 
specification in 
Requirement R3 or R4 
did not satisfy the 
obligations of the 
documented 
specifications for 
data. 

Page 8 of 10 

TOP‐003‐4 — Guidelines and Technical Basis 

D. Regional Variances
None. 
E. Interpretations
None. 
F. Associated Documents
None. 

Version History
Version 

Date 

0 

April 1, 2005 

0 

August 8, 2005 

1 

Action  

Effective Date 
Removed “Proposed” from Effective 
Date 
Modified R1.2  
Modified M1 

Change Tracking  

New 
Errata 
Revised 

Replaced Levels of Non‐compliance 
with the Feb 28, BOT approved 
Violation Severity Levels (VSLs) 
1 

October 17, 2008 

Adopted by NERC Board of Trustees 

1 

March 17, 2011 

Order issued by FERC approving TOP‐
003‐1 (approval effective 5/23/11) 

2 

May 6, 2012 

Revised under Project 2007‐03 

Revised 

2 

May 9, 2012 

Adopted by Board of Trustees 

Revised 

3 

April 2014 

Changes pursuant to Project 2014‐03 

Revised 

3 

November 13, 2014  Adopted by Board of Trustees 

3 

November 19, 2015  FERC approved TOP‐003‐3. Docket No. 
RM15‐16‐000, Order No. 817 
Adopted by Board of Trustees 

4 

Draft 12 of TOP‐003‐4 
October 2019January 2020 

Revisions under 
Project 2014‐03 

Page 9 of 10 

TOP‐003‐4 — Guidelines and Technical Basis 

Guidelines and Technical Basis 
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 Definitions:   
Changes made to the proposed definitions were made in order to respond to issues raised in 
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on 
Protection Systems and Special Protection Systems in NOPR paragraph 78, and 
recommendations on phase angles from the SW Outage Report (recommendation 27). The 
intent of such changes is to ensure that Real‐time Assessments contain sufficient details to 
result in an appropriate level of situational awareness.  Some examples include: 1) analyzing 
phase angles which may result in the implementation of an Operating Plan to adjust generation 
or curtail transactions so that a Transmission facility may be returned to service, or 2) 
evaluating the impact of a modified Contingency resulting from the status change of a Special 
Protection Scheme from enabled/in‐service to disabled/out‐of‐service. 

Rationale for R1:   
Changes to proposed Requirement R1, Part 1.1 are in response to issues raised in NOPR 
paragraph 67 on the need for obtaining non‐BES and external network data necessary for the 
Transmission Operator to fulfill its responsibilities.    
Proposed Requirement R1, Part 1.2 is in response to NOPR paragraph 78 on relay data. The 
language has been moved from approved PRC‐001‐1.  
Corresponding changes have been made to Requirement R2 for the Balancing Authority and to 
proposed IRO‐010‐2, Requirement R1 for the Reliability Coordinator.  

Rationale for R5:   
Proposed Requirement R5, Part 5.3 is in response to NOPR paragraph 92 where concerns were 
raised about data exchange through secured networks. 

Draft 12 of TOP‐003‐4 
October 2019January 2020 

Page 10 of 10 

Standard TOP-003-3 4 — Operational Reliability Data
A. Introduction
1.

Title: Operational Reliability Data

2.

Number: TOP-003-43

3.

Purpose: To ensure that the Transmission Operator and Balancing Authority have
data needed to fulfill their operational and planning responsibilities.

4.

Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Generator Owner
4.4. Generator Operator
4.5. Load-Serving Entity

5.

4.6.4.5.

Transmission Owner

4.7.4.6.

Distribution Provider

Effective Date:
See Implementation Plan.

6.

Background:
See Project 2014-03 project page.

B. Requirements and Measures
R1. Each Transmission Operator shall maintain a documented specification for the data
necessary for it to perform its Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments. The data specification shall include, but not be limited to:
[Violation Risk Factor: Low] [Time Horizon: Operations Planning]
1.1.

A list of data and information needed by the Transmission Operator to
support its Operational Planning Analyses, Real-time monitoring, and Realtime Assessments including non-BES data and external network data as
deemed necessary by the Transmission Operator.

1.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

1.3.

A periodicity for providing data.

1.4.

The deadline by which the respondent is to provide the indicated data.

M1. Each Transmission Operator shall make available its dated, current, in force
documented specification for data.

Page 1 of 10

Standard TOP-003-3 4 — Operational Reliability Data
R2.

Each Balancing Authority shall maintain a documented specification for the data
necessary for it to perform its analysis functions and Real-time monitoring. The data
specification shall include, but not be limited to: [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]
2.1.

A list of data and information needed by the Balancing Authority to support
its analysis functions and Real-time monitoring.

2.2.

Provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability.

2.3.

A periodicity for providing data.

2.4.

The deadline by which the respondent is to provide the indicated data.

M2. Each Balancing Authority shall make available its dated, current, in force documented
specification for data.
R3. Each Transmission Operator shall distribute its data specification to entities that have
data required by the Transmission Operator’s Operational Planning Analyses, Realtime monitoring, and Real-time Assessment. [Violation Risk Factor: Low] [Time
Horizon: Operations Planning]
M3. Each Transmission Operator shall make available evidence that it has distributed its
data specification to entities that have data required by the Transmission Operator’s
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments.
Such evidence could include but is not limited to web postings with an electronic
notice of the posting, dated operator logs, voice recordings, postal receipts showing
the recipient, date and contents, or e-mail records.
R4. Each Balancing Authority shall distribute its data specification to entities that have
data required by the Balancing Authority’s analysis functions and Real-time
monitoring. [Violation Risk Factor: Low] [Time Horizon: Operations Planning]
M4. Each Balancing Authority shall make available evidence that it has distributed its data
specification to entities that have data required by the Balancing Authority’s analysis
functions and Real-time monitoring. Such evidence could include but is not limited to
web postings with an electronic notice of the posting, dated operator logs, voice
recordings, postal receipts showing the recipient, or e-mail records.
R5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R3 or R4 shall satisfy the obligations of
the documented specifications using: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning, Same-Day Operations, Real-time Operations]
5.1. A mutually agreeable format
5.2. A mutually agreeable process for resolving data conflicts
5.3. A mutually agreeable security protocol

Page 2 of 10

Standard TOP-003-3 4 — Operational Reliability Data
M5. Each Transmission Operator, Balancing Authority, Generator Owner, Generator
Operator, Load-Serving Entity, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R3 or R4 shall make available evidence
that it has satisfied the obligations of the documented specifications. Such evidence
could include, but is not limited to, electronic or hard copies of data transmittals or
attestations of receiving entities.
C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Process
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Assessment Processes
As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated reliability standard.
1.3. Data 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 responsible entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation:
Each Transmission Operator shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its Operational Planning
Analyses, Real-time monitoring, and Real-time Assessments in accordance with
Requirement R1 and Measurement M1 as well as any documents in force since
the last compliance audit.
Each Balancing Authority shall retain its dated, current, in force, documented
specification for the data necessary for it to perform its analysis functions and
Real-time monitoring in accordance with Requirement R2 and Measurement M2
as well as any documents in force since the last compliance audit.
Each Transmission Operator shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the

Page 3 of 10

Standard TOP-003-3 4 — Operational Reliability Data
Transmission Operator’s Operational Planning Analyses, Real-time monitoring,
and Real-time Assessments in accordance with Requirement R3 and
Measurement M3.
Each Balancing Authority shall retain evidence for three calendar years that it
has distributed its data specification to entities that have data required by the
Balancing Authority’s analysis functions and Real-time monitoring in accordance
with Requirement R4 and Measurement M4.
Each Balancing Authority, Generator Owner, Generator Operator, Load-Serving
Entity, Transmission Operator, Transmission Owner, and Distribution Provider
receiving a data specification in Requirement R3 or R4 shall retain evidence for
the most recent 90-calendar days that it has satisfied the obligations of the
documented specifications in accordance with Requirement R5 and
Measurement M5.
If a responsible entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved or the time
period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.

Page 4 of 10

Standard TOP-003-3 4 — Operational Reliability Data
Table of Compliance Elements
R#

R1

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Transmission
Operator did not
include one of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include two of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include three of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Transmission
Operator did not
include four of the
parts (Part 1.1
through Part 1.4) of
the documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.
OR,
The Transmission
Operator did not have
a documented
specification for the
data necessary for it
to perform its
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

Page 5 of 10

Standard TOP-003-3 4 — Operational Reliability Data
R#

R2

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Balancing
Authority did not
include one of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include two of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include three of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

The Balancing
Authority did not
include four of the
parts (Part 2.1
through Part 2.4) of
the documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.
OR,
The Balancing
Authority did not
have a documented
specification for the
data necessary for it
to perform its analysis
functions and Realtime monitoring.

For the Requirement R3 and R4 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to
the left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity
has just one affected reliability entity to inform, the intent is that that situation would be a Severe violation.
R3

Operations
Planning

Low

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

The Transmission
Operator did not
distribute its data

Page 6 of 10

Standard TOP-003-3 4 — Operational Reliability Data
R#

R4

Time Horizon

Operations
Planning

Violation Severity Levels

VRF

Low

Lower VSL

Moderate VSL

High VSL

Severe VSL

specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to two
entities, or more than
5% and less than or
equal to10% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to three
entities, or more than
10% and less than or
equal to 15% of the
reliability entities,
whichever is greater,
that have data
required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Transmission
Operator’s
Operational Planning
Analyses, Real-time
monitoring, and Realtime Assessments.

The Balancing
Authority did not
distribute its data
specification to one
entity, or 5% or less of
the entities,
whichever is greater,
that have data
required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to two
entities, or more than
5% and less than or
equal to 10% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to three
entities, or more than
10% and less than or
equal to 15% of the
entities, whichever is
greater, that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

The Balancing
Authority did not
distribute its data
specification to four
or more entities, or
more than 15% of the
entities that have
data required by the
Balancing Authority’s
analysis functions and
Real-time monitoring.

Page 7 of 10

Standard TOP-003-3 4 — Operational Reliability Data
R#

R5

Time Horizon

Operations
Planning,
Same-Day
Operations,
Real-time
Operations

Violation Severity Levels

VRF

Medium

Lower VSL

Moderate VSL

High VSL

Severe VSL

The responsible
entity receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet one of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet two of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
satisfied the
obligations in the data
specification but did
not meet three of the
criteria shown in
Requirement R5
(Parts 5.1 – 5.3).

The responsible entity
receiving a data
specification in
Requirement R3 or R4
did not satisfy the
obligations of the
documented
specifications for
data.

Page 8 of 10

Standard TOP-003-3 4 — Guidelines and Technical Basis
D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Version History
Version

Date

0

April 1, 2005

0

August 8, 2005

Action
Effective Date
Removed “Proposed” from Effective
Date
Modified R1.2
Modified M1

1

Change Tracking
New
Errata
Revised

Replaced Levels of Non-compliance
with the Feb 28, BOT approved
Violation Severity Levels (VSLs)
1

October 17, 2008

Adopted by NERC Board of Trustees

1

March 17, 2011

Order issued by FERC approving TOP003-1 (approval effective 5/23/11)

2

May 6, 2012

Revised under Project 2007-03

Revised

2

May 9, 2012

Adopted by Board of Trustees

Revised

3

April 2014

Changes pursuant to Project 2014-03

Revised

3

November 13, 2014 Adopted by Board of Trustees

3

November 19, 2015 FERC approved TOP-003-3. Docket No.
RM15-16-000, Order No. 817
Adopted by Board of Trustees

4

Revisions under
Project 2014-03

Page 9 of 10

Standard TOP-003-3 4 — Guidelines and Technical Basis
Guidelines and Technical Basis
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 Definitions:
Changes made to the proposed definitions were made in order to respond to issues raised in
NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on
Protection Systems and Special Protection Systems in NOPR paragraph 78, and
recommendations on phase angles from the SW Outage Report (recommendation 27). The
intent of such changes is to ensure that Real-time Assessments contain sufficient details to
result in an appropriate level of situational awareness. Some examples include: 1) analyzing
phase angles which may result in the implementation of an Operating Plan to adjust generation
or curtail transactions so that a Transmission facility may be returned to service, or 2)
evaluating the impact of a modified Contingency resulting from the status change of a Special
Protection Scheme from enabled/in-service to disabled/out-of-service.
Rationale for R1:
Changes to proposed Requirement R1, Part 1.1 are in response to issues raised in NOPR
paragraph 67 on the need for obtaining non-BES and external network data necessary for the
Transmission Operator to fulfill its responsibilities.
Proposed Requirement R1, Part 1.2 is in response to NOPR paragraph 78 on relay data. The
language has been moved from approved PRC-001-1.
Corresponding changes have been made to Requirement R2 for the Balancing Authority and to
proposed IRO-010-2, Requirement R1 for the Reliability Coordinator.
Rationale for R5:
Proposed Requirement R5, Part 5.3 is in response to NOPR paragraph 92 where concerns were
raised about data exchange through secured networks.

Page 10 of 10

Implementation Plan

Project 2017-07 Standards Alignment with Registration
Applicable Standards
•

FAC-002-3 – Facility Interconnection Studies

•

IRO-010-3 – Reliability Coordinator Data Specification and Collection

•

MOD-031-3 – Demand and Energy Data

•

MOD-033-2 – Steady-State and Dynamic System Model Validation

•

NUC-001-4 – Nuclear Plant Interface Coordination

•

PRC-006-4 – Automatic Underfrequency Load Shedding

•

TOP-003-4 – Operational Reliability Data

Requested Retirements
•

FAC-002-2 – Facility Interconnection Studies

•

IRO-010-2 – Reliability Coordinator Data Specification and Collection

•

MOD-031-2 – Demand and Energy Data

•

MOD-033-1 – Steady-State and Dynamic System Model Validation

•

NUC-001-3 – Nuclear Plant Interface Coordination

•

PRC-006-3 – Automatic Underfrequency Load Shedding

•

TOP-003-3 – Operational Reliability Data

Applicable Entities
See subject standards.
Background
On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North
American Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) initiative in Docket
No. RR15-4-000. FERC approved the removal of two functional categories, Purchasing-Selling Entity
(PSE) and Interchange Authority (IA), from the NERC Compliance Registry due to the commercial
nature of these categories posing little or no risk to the reliability of the bulk power system. FERC
also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently approved
on compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria.

RELIABILITY | RESILIENCE | SECURITY

Several projects have addressed standards impacted by the RBR initiative since FERC approval;
however, there remain some Reliability Standards that require minor revisions so that they align
with the post-RBR registration impacts.
Project 2017-07 Standards Alignment with Registration formally addressed the remaining edits to
the Reliability Standards that are needed to align the existing standards with the RBR
initiatives. The edits include updates to the FAC, IRO, MOD, NUC, and TOP family of standards.
References to Load-Serving Entity (LSEs) were removed or replaced by the appropriate NERC
Registered Entity. PRC-006 was updated to include the more-limited UFLS-only Distribution
Provider (DP) to the Applicability Section. A majority of the edits simply removed deregistered
functional entities and their applicable requirements/references.
Effective Date
Reliability Standards FAC-002-3, IRO-010-3, MOD-031-3, MOD-033-2, NUC-001-4, PRC-006-4, and TOP003-4
Where approval by an applicable governmental authority is required, the standard shall become
effective on the first day of the first calendar quarter that is three (3) months after the effective date of
the applicable governmental authority’s order approving the standard, or as otherwise provided for by
the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is three (3) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Retirement Date
Reliability Standards FAC-002-2, IRO-010-2, MOD-031-2, MOD-033-1, NUC-001-3, PRC-006-

3, and TOP-003-3

The Reliability Standard shall be retired immediately prior to the effective date of the revised standard
in the particular jurisdiction in which the revised standard is becoming effective.

Implementation Plan
Project 2017-07 Standards Alignment with Registration | January 2020

2

Implementation Plan

Project 2017-07 Standards Alignment with Registration
Applicable Standards
•

FAC-002-3 – Facility Interconnection Studies

•

IRO-010-3 – Reliability Coordinator Data Specification and Collection

•

MOD-031-3 – Demand and Energy Data

•

MOD-033-2 – Steady-State and Dynamic System Model Validation

•

NUC-001-4 – Nuclear Plant Interface Coordination

•

PRC-006-4 – Automatic Underfrequency Load Shedding

•

TOP-003-4 – Operational Reliability Data

Requested Retirements
•

FAC-002-2 – Facility Interconnection Studies

•

IRO-010-2 – Reliability Coordinator Data Specification and Collection

•

MOD-031-2 – Demand and Energy Data

•

MOD-033-1 – Steady-State and Dynamic System Model Validation

•

NUC-001-3 – Nuclear Plant Interface Coordination

•

PRC-006-3 – Automatic Underfrequency Load Shedding

•

TOP-003-3 – Operational Reliability Data

Applicable Entities
See subject standards.
Background
On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North
American Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) initiative in Docket
No. RR15-4-000. FERC approved the removal of two functional categories, Purchasing-Selling Entity
(PSE) and Interchange Authority (IA), from the NERC Compliance Registry due to the commercial
nature of these categories posing little or no risk to the reliability of the bulk power system. FERC
also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently approved
on compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria.

RELIABILITY | RESILIENCE | SECURITY

Several projects have addressed standards impacted by the RBR initiative since FERC approval;
however, there remain some Reliability Standards that require minor revisions so that they align
with the post-RBR registration impacts.
Project 2017-07 Standards Alignment with Registration formally addressed the remaining edits to
the Reliability Standards that are needed to align the existing standards with the RBR
initiatives. The edits include updates to the FAC, IRO, MOD, NUC, and TOP family of standards.
References to Load-Serving Entity (LSEs) were removed or replaced by the appropriate NERC
Registered Entity. PRC-006 was updated to include replace Distribution Providers (DP) with the
more-limited UFLS-only Distribution Provider (DP) to the Applicability Section. A majority of the
edits simply removed deregistered functional entities and their applicable
requirements/references.
Effective Date
Reliability Standards FAC-002-3, IRO-010-3, MOD-031-3, MOD-033-2, NUC-001-4, PRC-006-4, and TOP003-4
Where approval by an applicable governmental authority is required, the standard shall become
effective on the first day of the first calendar quarter that is three (3) months after the effective date of
the applicable governmental authority’s order approving the standard, or as otherwise provided for by
the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is three (3) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Retirement Date
Reliability Standards FAC-002-2, IRO-010-2, MOD-031-2, MOD-033-1, NUC-001-3, PRC-0063, and TOP-003-3
The Reliability Standard shall be retired immediately prior to the effective date of the revised standard
in the particular jurisdiction in which the revised standard is becoming effective.

Implementation Plan
Project 2017-07 Standards Alignment with Registration | October December January 20192020

2

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, FAC-002-3. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for FAC-002-3, Requirement R1
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R1
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF Justification for FAC-002-3, Requirement R2
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R2
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF Justification for FAC-002-3, Requirement R3
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R3
This justification is provided on the following page.
VRF Justification for FAC-002-3, Requirement R4
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R4
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF Justification for FAC-002-3, Requirement R5
The VRF did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VSL Justification for FAC-002-3, Requirement R5
The VSL did not change from the previously FERC approved FAC-002-2 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

VSLs for FAC-002-3, Requirement R3

Lower

Moderate

High

Severe

The Transmission Owner or
Distribution Provider seeking to
interconnect new transmission
Facilities or electricity end-user
Facilities, or to materially modify
existing interconnections of
transmission Facilities or
electricity end-user Facilities,
coordinated and cooperated on
studies with its Transmission
Planner or Planning Coordinator,
but failed to provide data
necessary to perform studies as
described in one of the Parts
(R1, 1.1-1.4).

The Transmission Owner, or
Distribution Provider Entity
seeking to interconnect new
transmission Facilities or
electricity end-user Facilities, or
to materially modify existing
interconnections of transmission
Facilities or electricity end-user
Facilities, coordinated and
cooperated on studies with its
Transmission Planner or
Planning Coordinator, but failed
to provide data necessary to
perform studies as described in
two of the Parts (R1, 1.1-1.4).

The Transmission Owner or
Distribution Provider Entity
seeking to interconnect new
transmission Facilities or
electricity end-user Facilities, or
to materially modify existing
interconnections of transmission
Facilities or electricity end-user
Facilities, coordinated and
cooperated on studies with its
Transmission Planner or
Planning Coordinator, but failed
to provide data necessary to
perform studies as described in
three of the Parts (R1, 1.1-1.4).

The Transmission Owner, or
Distribution Provider Entity
seeking to interconnect new
transmission Facilities or
electricity end-user Facilities, or
to materially modify existing
interconnections of transmission
Facilities or electricity end-user
Facilities, failed to coordinate
and cooperate on studies with
its Transmission Planner or
Planning Coordinator.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

6

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity 
levels (VSLs) for each requirement in Project 2017‐07 Standards Alignment with Registration, FAC‐002‐3. Each requirement is assigned a VRF 
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of 
requirements in FERC‐approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT 
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements. 

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of 
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a 
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly 
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System 
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition. 

Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively 
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System 
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, 
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is 
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability, 
separation, or cascading failures, nor to hinder restoration to a normal condition. 

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical 
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that 
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or 
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.  

FERC Guidelines for Violation Risk Factors

Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical 
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where 
violations could severely affect the reliability of the Bulk‐Power System: 


Emergency operations 



Vegetation management 



Operator personnel training 



Protection systems and their coordination 



Operating tools and backup facilities 



Reactive power and voltage control 



System modeling and data exchange 



Communication protocol and facilities 



Requirements to determine equipment ratings 



Synchronized data recorders 



Clearer criteria for operationally critical facilities 



Appropriate use of transmission loading relief. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October 2019January 2020 

2 

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment. 

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards 
would be treated comparably. 

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level. 

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such 
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability 
Standard. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October 2019January 2020 

3 

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is 
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and 
may have only one, two, or three VSLs. 

VSLs should be based on NERC’s overarching criteria shown in the table below: 

Lower VSL

The performance or product 
measured almost meets the full 
intent of the requirement.   

Moderate VSL

High VSL

The performance or product 
The performance or product 
measured meets the majority of  measured does not meet the 
the intent of the requirement.    majority of the intent of the 
requirement, but does meet 
some of the intent. 

Severe VSL

The performance or product 
measured does not 
substantively meet the intent of 
the requirement.   

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard 
meet the FERC Guidelines for assessing VSLs: 

Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than 
was required when levels of non‐compliance were used. 

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL. 
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance. 

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October 2019January 2020 

4 

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the 
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations. 

VRF Justification for FAC‐002‐3, Requirement R1 
The VRF did not change from the previously FERC approved FAC‐002‐2 Reliability Standard. 

VSL Justification for FAC‐002‐3, Requirement R1  
The VSL did not change from the previously FERC approved FAC‐002‐2 Reliability Standard. 

VRF Justification for FAC‐002‐3, Requirement R2  
The VRF did not change from the previously FERC approved FAC‐002‐2 Reliability Standard. 

VSL Justification for FAC‐002‐3, Requirement R2  
The VSL did not change from the previously FERC approved FAC‐002‐2 Reliability Standard. 

VRF Justification for FAC‐002‐3, Requirement R3 
The VRF did not change from the previously FERC approved FAC‐002‐2 Reliability Standard. 

VSL Justification for FAC‐002‐3, Requirement R3  
This justification is provided on the following page. 

VRF Justification for FAC‐002‐3, Requirement R4  
The VRF did not change from the previously FERC approved FAC‐002‐2 Reliability Standard. 

VSL Justification for FAC‐002‐3, Requirement R4  
The VSL did not change from the previously FERC approved FAC‐002‐2 Reliability Standard. 

VRF Justification for FAC‐002‐3, Requirement R5 
The VRF did not change from the previously FERC approved FAC‐002‐2 Reliability Standard. 

VSL Justification for FAC‐002‐3, Requirement R5  
The VSL did not change from the previously FERC approved FAC‐002‐2 Reliability Standard.
VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October 2019January 2020 

5 

VSLs for FAC-002-3, Requirement R3

Lower 

Moderate 

High 

Severe 

The Transmission Owner or 
Distribution Provider seeking to 
interconnect new transmission 
Facilities or electricity end‐user 
Facilities, or to materially modify 
existing interconnections of 
transmission Facilities or 
electricity end‐user Facilities, 
coordinated and cooperated on 
studies with its Transmission 
Planner or Planning Coordinator, 
but failed to provide data 
necessary to perform studies as 
described in one of the Parts 
(R1, 1.1‐1.4). 

The Transmission Owner, or 
Distribution Provider Entity 
seeking to interconnect new 
transmission Facilities or 
electricity end‐user Facilities, or 
to materially modify existing 
interconnections of transmission 
Facilities or electricity end‐user 
Facilities, coordinated and 
cooperated on studies with its 
Transmission Planner or 
Planning Coordinator, but failed 
to provide data necessary to 
perform studies as described in 
two of the Parts (R1, 1.1‐1.4). 

The Transmission Owner or 
Distribution Provider Entity 
seeking to interconnect new 
transmission Facilities or 
electricity end‐user Facilities, or 
to materially modify existing 
interconnections of transmission 
Facilities or electricity end‐user 
Facilities, coordinated and 
cooperated on studies with its 
Transmission Planner or 
Planning Coordinator, but failed 
to provide data necessary to 
perform studies as described in 
three of the Parts (R1, 1.1‐1.4). 

The Transmission Owner, or 
Distribution Provider Entity 
seeking to interconnect new 
transmission Facilities or 
electricity end‐user Facilities, or 
to materially modify existing 
interconnections of transmission 
Facilities or electricity end‐user 
Facilities, failed to coordinate 
and cooperate on studies with 
its Transmission Planner or 
Planning Coordinator. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October 2019January 2020 

6 

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, IRO-010-3. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for IRO-010-3, Requirement R1
The VRF did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VSL Justification for IRO-010-3, Requirement R1
The VSL did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VRF Justification for IRO-010-3, Requirement R2
The VRF did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VSL Justification for IRO-010-3, Requirement R2
The VSL did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VRF Justification for IRO-010-3, Requirement R3
The VRF did not change from the previously FERC approved IRO-010-2 Reliability Standard.
VSL Justification for IRO-010-3, Requirement R3
The VSL did not change from the previously FERC approved IRO-010-2 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity 
levels (VSLs) for each requirement in Project 2017‐07 Standards Alignment with Registration, IRO‐010‐3. Each requirement is assigned a VRF 
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of 
requirements in FERC‐approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT 
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements. 

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of 
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a 
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly 
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System 
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition. 

Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively 
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System 
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, 
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is 
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability, 
separation, or cascading failures, nor to hinder restoration to a normal condition. 

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical 
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that 
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or 
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.  

FERC Guidelines for Violation Risk Factors

Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical 
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where 
violations could severely affect the reliability of the Bulk‐Power System: 


Emergency operations 



Vegetation management 



Operator personnel training 



Protection systems and their coordination 



Operating tools and backup facilities 



Reactive power and voltage control 



System modeling and data exchange 



Communication protocol and facilities 



Requirements to determine equipment ratings 



Synchronized data recorders 



Clearer criteria for operationally critical facilities 



Appropriate use of transmission loading relief. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

2 

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment. 

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards 
would be treated comparably. 

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level. 

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such 
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability 
Standard. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

3 

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is 
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and 
may have only one, two, or three VSLs. 

VSLs should be based on NERC’s overarching criteria shown in the table below: 

Lower VSL

The performance or product 
measured almost meets the full 
intent of the requirement.   

Moderate VSL

High VSL

The performance or product 
The performance or product 
measured meets the majority of  measured does not meet the 
the intent of the requirement.    majority of the intent of the 
requirement, but does meet 
some of the intent. 

Severe VSL

The performance or product 
measured does not 
substantively meet the intent of 
the requirement.   

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard 
meet the FERC Guidelines for assessing VSLs: 

Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than 
was required when levels of non‐compliance were used. 

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL. 
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance. 

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

4 

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the 
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations. 

VRF Justification for IRO‐010‐3, Requirement R1 
The VRF did not change from the previously FERC approved IRO‐010‐2 Reliability Standard. 

VSL Justification for IRO‐010‐3, Requirement R1  
The VSL did not change from the previously FERC approved IRO‐010‐2 Reliability Standard. 

VRF Justification for IRO‐010‐3, Requirement R2  
The VRF did not change from the previously FERC approved IRO‐010‐2 Reliability Standard. 

VSL Justification for IRO‐010‐3, Requirement R2  
The VSL did not change from the previously FERC approved IRO‐010‐2 Reliability Standard. 

VRF Justification for IRO‐010‐3, Requirement R3 
The VRF did not change from the previously FERC approved IRO‐010‐2 Reliability Standard. 

VSL Justification for IRO‐010‐3, Requirement R3  
The VSL did not change from the previously FERC approved IRO‐010‐2 Reliability Standard. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

5 

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, MOD-031-3. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for MOD-031-3, Requirement R1
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R1
The VSL did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VRF Justification for MOD-031-3, Requirement R2
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R2
The VSL did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VRF Justification for MOD-031-3, Requirement R3
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R3
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VRF Justification for MOD-031-3, Requirement R4
The VRF did not change from the previously FERC approved MOD-031-2 Reliability Standard.
VSL Justification for MOD-031-3, Requirement R4
The VSL did not change from the previously FERC approved MOD-031-2 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity 
levels (VSLs) for each requirement in Project 2017‐07 Standards Alignment with Registration, MOD‐031‐3. Each requirement is assigned a VRF 
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of 
requirements in FERC‐approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT 
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements. 

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of 
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a 
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly 
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System 
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition. 

Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively 
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System 
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, 
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is 
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability, 
separation, or cascading failures, nor to hinder restoration to a normal condition. 

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical 
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that 
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or 
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.  

FERC Guidelines for Violation Risk Factors

Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical 
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where 
violations could severely affect the reliability of the Bulk‐Power System: 


Emergency operations 



Vegetation management 



Operator personnel training 



Protection systems and their coordination 



Operating tools and backup facilities 



Reactive power and voltage control 



System modeling and data exchange 



Communication protocol and facilities 



Requirements to determine equipment ratings 



Synchronized data recorders 



Clearer criteria for operationally critical facilities 



Appropriate use of transmission loading relief. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | DecemberJanuary 20192020 

2 

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment. 

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards 
would be treated comparably. 

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level. 

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such 
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability 
Standard. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | DecemberJanuary 20192020 

3 

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is 
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and 
may have only one, two, or three VSLs. 

VSLs should be based on NERC’s overarching criteria shown in the table below: 

Lower VSL

The performance or product 
measured almost meets the full 
intent of the requirement.   

Moderate VSL

High VSL

The performance or product 
The performance or product 
measured meets the majority of  measured does not meet the 
the intent of the requirement.    majority of the intent of the 
requirement, but does meet 
some of the intent. 

Severe VSL

The performance or product 
measured does not 
substantively meet the intent of 
the requirement.   

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard 
meet the FERC Guidelines for assessing VSLs: 

Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than 
was required when levels of non‐compliance were used. 

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL. 
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance. 

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | DecemberJanuary 20192020 

4 

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the 
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations. 

VRF Justification for MOD‐031‐3, Requirement R1 
The VRF did not change from the previously FERC approved MOD‐031‐2 Reliability Standard. 

VSL Justification for MOD‐031‐3, Requirement R1  
The VSL did not change from the previously FERC approved MOD‐031‐2 Reliability Standard. 

VRF Justification for MOD‐031‐3, Requirement R2  
The VRF did not change from the previously FERC approved MOD‐031‐2 Reliability Standard. 

VSL Justification for MOD‐031‐3, Requirement R2  
The VSL did not change from the previously FERC approved MOD‐031‐2 Reliability Standard. 

VRF Justification for MOD‐031‐3, Requirement R3 
The VRF did not change from the previously FERC approved MOD‐031‐2 Reliability Standard. 

VSL Justification for MOD‐031‐3, Requirement R3  
The VRF did not change from the previously FERC approved MOD‐031‐2 Reliability Standard. 

VRF Justification for MOD‐031‐3, Requirement R4  
The VRF did not change from the previously FERC approved MOD‐031‐2 Reliability Standard. 

VSL Justification for MOD‐031‐3, Requirement R4  
The VSL did not change from the previously FERC approved MOD‐031‐2 Reliability Standard. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | DecemberJanuary 20192020 

5 

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, MOD-033-2. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for MOD-033-2, Requirement R1
The VRF did not change from the previously FERC approved MOD-033-1 Reliability Standard.
VSL Justification for F MOD-033-2, Requirement R1
The VSL did not change from the previously FERC approved MOD-033-1 Reliability Standard.
VRF Justification for MOD-033-2, Requirement R2
The VRF did not change from the previously FERC approved MOD-033-1 Reliability Standard.
VSL Justification for MOD-033-2, Requirement R2
The VSL did not change from the previously FERC approved MOD-033-1 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity 
levels (VSLs) for each requirement in Project 2017‐07 Standards Alignment with Registration, MOD‐033‐2. Each requirement is assigned a VRF 
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of 
requirements in FERC‐approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT 
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements. 

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of 
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a 
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly 
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System 
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition. 

Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively 
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System 
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, 
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is 
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability, 
separation, or cascading failures, nor to hinder restoration to a normal condition. 

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical 
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that 
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or 
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.  

FERC Guidelines for Violation Risk Factors

Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical 
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where 
violations could severely affect the reliability of the Bulk‐Power System: 


Emergency operations 



Vegetation management 



Operator personnel training 



Protection systems and their coordination 



Operating tools and backup facilities 



Reactive power and voltage control 



System modeling and data exchange 



Communication protocol and facilities 



Requirements to determine equipment ratings 



Synchronized data recorders 



Clearer criteria for operationally critical facilities 



Appropriate use of transmission loading relief. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

2 

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment. 

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards 
would be treated comparably. 

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level. 

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such 
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability 
Standard. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

3 

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is 
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and 
may have only one, two, or three VSLs. 

VSLs should be based on NERC’s overarching criteria shown in the table below: 

Lower VSL

The performance or product 
measured almost meets the full 
intent of the requirement.   

Moderate VSL

High VSL

The performance or product 
The performance or product 
measured meets the majority of  measured does not meet the 
the intent of the requirement.    majority of the intent of the 
requirement, but does meet 
some of the intent. 

Severe VSL

The performance or product 
measured does not 
substantively meet the intent of 
the requirement.   

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard 
meet the FERC Guidelines for assessing VSLs: 

Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than 
was required when levels of non‐compliance were used. 

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL. 
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance. 

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

4 

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the 
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations. 

VRF Justification for MOD‐033‐2, Requirement R1 
The VRF did not change from the previously FERC approved MOD‐033‐1 Reliability Standard. 

VSL Justification for F MOD‐033‐2, Requirement R1  
The VSL did not change from the previously FERC approved MOD‐033‐1 Reliability Standard. 

VRF Justification for MOD‐033‐2, Requirement R2  
The VRF did not change from the previously FERC approved MOD‐033‐1 Reliability Standard. 

VSL Justification for MOD‐033‐2, Requirement R2  
The VSL did not change from the previously FERC approved MOD‐033‐1 Reliability Standard. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

5 

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, NUC-001-4. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for NUC-001-4, Requirement R1
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.

VSL Justification for NUC-001-4, Requirement R1
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R2
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R2
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R3
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R3
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R4
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R4
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R5
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R5
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

VRF Justification for NUC-001-4, Requirement R6
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R6
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R7
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R7
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R8
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R8
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VRF Justification for NUC-001-4, Requirement R9
The VRF did not change from the previously FERC approved NUC-001-3 Reliability Standard.
VSL Justification for NUC-001-4, Requirement R9
The VSL did not change from the previously FERC approved NUC-001-3 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

6

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity 
levels (VSLs) for each requirement in Project 2017‐07 Standards Alignment with Registration, NUC‐001‐4. Each requirement is assigned a VRF 
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of 
requirements in FERC‐approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT 
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements. 

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of 
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a 
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly 
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System 
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition. 

Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively 
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System 
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, 
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is 
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability, 
separation, or cascading failures, nor to hinder restoration to a normal condition. 

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical 
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that 
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or 
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.  

FERC Guidelines for Violation Risk Factors

Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical 
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where 
violations could severely affect the reliability of the Bulk‐Power System: 


Emergency operations 



Vegetation management 



Operator personnel training 



Protection systems and their coordination 



Operating tools and backup facilities 



Reactive power and voltage control 



System modeling and data exchange 



Communication protocol and facilities 



Requirements to determine equipment ratings 



Synchronized data recorders 



Clearer criteria for operationally critical facilities 



Appropriate use of transmission loading relief. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 201920 

2 

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment. 

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards 
would be treated comparably. 

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level. 

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such 
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability 
Standard. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 201920 

3 

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is 
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and 
may have only one, two, or three VSLs. 

VSLs should be based on NERC’s overarching criteria shown in the table below: 

Lower VSL

The performance or product 
measured almost meets the full 
intent of the requirement.   

Moderate VSL

High VSL

The performance or product 
The performance or product 
measured meets the majority of  measured does not meet the 
the intent of the requirement.    majority of the intent of the 
requirement, but does meet 
some of the intent. 

Severe VSL

The performance or product 
measured does not 
substantively meet the intent of 
the requirement.   

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard 
meet the FERC Guidelines for assessing VSLs: 

Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than 
was required when levels of non‐compliance were used. 

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL. 
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance. 

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 201920 

4 

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the 
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations. 

VRF Justification for NUC‐001‐4, Requirement R1 
The VRF did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VSL Justification for NUC‐001‐4, Requirement R1  
The VSL did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VRF Justification for NUC‐001‐4, Requirement R2  
The VRF did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VSL Justification for NUC‐001‐4, Requirement R2  
The VSL did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VRF Justification for NUC‐001‐4, Requirement R3 
The VRF did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VSL Justification for NUC‐001‐4, Requirement R3  
The VSL did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VRF Justification for NUC‐001‐4, Requirement R4  
The VRF did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VSL Justification for NUC‐001‐4, Requirement R4  
The VSL did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VRF Justification for NUC‐001‐4, Requirement R5 
The VRF did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VSL Justification for NUC‐001‐4, Requirement R5  
The VSL did not change from the previously FERC approved NUC‐001‐3 Reliability Standard.
VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 201920 

5 

VRF Justification for NUC‐001‐4, Requirement R6 
The VRF did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VSL Justification for NUC‐001‐4, Requirement R6  
The VSL did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 
VRF Justification for NUC‐001‐4, Requirement R7 
The VRF did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VSL Justification for NUC‐001‐4, Requirement R7  
The VSL did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VRF Justification for NUC‐001‐4, Requirement R8 
The VRF did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VSL Justification for NUC‐001‐4, Requirement R8  
The VSL did not change from the previously FERC approved NUC‐001‐3 Reliability Standard.
VRF Justification for NUC‐001‐4, Requirement R9 
The VRF did not change from the previously FERC approved NUC‐001‐3 Reliability Standard. 

VSL Justification for NUC‐001‐4, Requirement R9  
The VSL did not change from the previously FERC approved NUC‐001‐3 Reliability Standard.

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 201920 

6 

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, PRC-006-4. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for PRC-006-4, Requirement R1
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R1
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R2
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R2
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R3
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R3
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R4
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R4
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R5
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R5
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

VRF Justification for PRC-006-4, Requirement R6
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R6
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R7
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R7
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R8
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R8
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R9
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R9
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R10
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R10
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R11
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

6

VSL Justification for PRC-006-4, Requirement R11
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R12
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R12
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R13
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R13
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R14
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R14
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VRF Justification for PRC-006-4, Requirement R15
The VRF did not change from the previously FERC approved PRC-006-3 Reliability Standard.
VSL Justification for PRC-006-4, Requirement R15
The VSL did not change from the previously FERC approved PRC-006-3 Reliability Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

7

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity 
levels (VSLs) for each requirement in Project 2017‐07 Standards Alignment with Registration, PRC‐006‐4. Each requirement is assigned a VRF 
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of 
requirements in FERC‐approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT 
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements. 

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of 
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a 
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly 
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System 
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition. 

Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively 
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System 
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, 
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is 
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability, 
separation, or cascading failures, nor to hinder restoration to a normal condition. 

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical 
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that 
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or 
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.  

FERC Guidelines for Violation Risk Factors

Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical 
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where 
violations could severely affect the reliability of the Bulk‐Power System: 


Emergency operations 



Vegetation management 



Operator personnel training 



Protection systems and their coordination 



Operating tools and backup facilities 



Reactive power and voltage control 



System modeling and data exchange 



Communication protocol and facilities 



Requirements to determine equipment ratings 



Synchronized data recorders 



Clearer criteria for operationally critical facilities 



Appropriate use of transmission loading relief. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

2 

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment. 

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards 
would be treated comparably. 

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level. 

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such 
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability 
Standard. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

3 

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is 
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and 
may have only one, two, or three VSLs. 

VSLs should be based on NERC’s overarching criteria shown in the table below: 

Lower VSL

The performance or product 
measured almost meets the full 
intent of the requirement.   

Moderate VSL

High VSL

The performance or product 
The performance or product 
measured meets the majority of  measured does not meet the 
the intent of the requirement.    majority of the intent of the 
requirement, but does meet 
some of the intent. 

Severe VSL

The performance or product 
measured does not 
substantively meet the intent of 
the requirement.   

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard 
meet the FERC Guidelines for assessing VSLs: 

Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than 
was required when levels of non‐compliance were used. 

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL. 
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance. 

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

4 

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the 
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations. 

VRF Justification for PRC‐006‐4, Requirement R1 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R1  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VRF Justification for PRC‐006‐4, Requirement R2  
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R2  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VRF Justification for PRC‐006‐4, Requirement R3 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R3  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VRF Justification for PRC‐006‐4, Requirement R4  
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R4  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VRF Justification for PRC‐006‐4, Requirement R5 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R5  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard.
VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

5 

VRF Justification for PRC‐006‐4, Requirement R6 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R6  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 
VRF Justification for PRC‐006‐4, Requirement R7 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R7  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VRF Justification for PRC‐006‐4, Requirement R8 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R8  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard.
VRF Justification for PRC‐006‐4, Requirement R9 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R9  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VRF Justification for PRC‐006‐4, Requirement R10 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R10  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard.
VRF Justification for PRC‐006‐4, Requirement R11 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

6 

VSL Justification for PRC‐006‐4, Requirement R11  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard.
VRF Justification for PRC‐006‐4, Requirement R12 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R12  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard.
VRF Justification for PRC‐006‐4, Requirement R13 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R13  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard.
VRF Justification for PRC‐006‐4, Requirement R14 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R14  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard.
VRF Justification for PRC‐006‐4, Requirement R15 
The VRF did not change from the previously FERC approved PRC‐006‐3 Reliability Standard. 

VSL Justification for PRC‐006‐4, Requirement R15  
The VSL did not change from the previously FERC approved PRC‐006‐3 Reliability Standard.

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | October January 20192020 

7 

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in Project 2017-07 Standards Alignment with Registration, TOP-003-4. Each requirement is assigned a VRF
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements.

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•

Emergency operations

•

Vegetation management

•

Operator personnel training

•

Protection systems and their coordination

•

Operating tools and backup facilities

•

Reactive power and voltage control

•

System modeling and data exchange

•

Communication protocol and facilities

•

Requirements to determine equipment ratings

•

Synchronized data recorders

•

Clearer criteria for operationally critical facilities

•

Appropriate use of transmission loading relief.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

2

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

3

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL

Moderate VSL

The performance or product
measured almost meets the full
intent of the requirement.

The performance or product
measured meets the majority of
the intent of the requirement.

High VSL

The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL

The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement.

VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

4

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF Justification for TOP-003-4, Requirement R1
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R1
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R2
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R2
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R3
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R3
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R4
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R4
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF Justification for TOP-003-4, Requirement R5
The VRF did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VSL Justification for TOP-003-4, Requirement R5
The VSL did not change from the previously FERC approved TOP-003-3 Reliability Standard.
VRF and VSL Justifications
Project 2017-07 Standards Alignment with Registration | January 2020

5

Violation Risk Factor and Violation Severity Level
Justifications
Project 2017-07 Standards Alignment with Registration

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity 
levels (VSLs) for each requirement in Project 2017‐07 Standards Alignment with Registration, TOP‐003‐4. Each requirement is assigned a VRF 
and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of 
requirements in FERC‐approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT 
applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements. 

NERC Criteria for Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of 
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a 
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly 
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System 
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition. 

Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively 
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System 
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, 
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is 
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability, 
separation, or cascading failures, nor to hinder restoration to a normal condition. 

RELIABILITY | RESILIENCE | SECURITY

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical 
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that 
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or 
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric 
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.  

FERC Guidelines for Violation Risk Factors

Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical 
critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where 
violations could severely affect the reliability of the Bulk‐Power System: 


Emergency operations 



Vegetation management 



Operator personnel training 



Protection systems and their coordination 



Operating tools and backup facilities 



Reactive power and voltage control 



System modeling and data exchange 



Communication protocol and facilities 



Requirements to determine equipment ratings 



Synchronized data recorders 



Clearer criteria for operationally critical facilities 



Appropriate use of transmission loading relief. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | OctoberJanuary 20192020 

2 

Guideline (2) – Consistency within a Reliability Standard

FERC expects a rational connection between the sub‐Requirement VRF assignments and the main Requirement VRF assignment. 

Guideline (3) – Consistency among Reliability Standards

FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards 
would be treated comparably. 

Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level. 

Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such 
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability 
Standard. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | OctoberJanuary 20192020 

3 

NERC Criteria for Violation Severity Levels

VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is 
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and 
may have only one, two, or three VSLs. 

VSLs should be based on NERC’s overarching criteria shown in the table below: 

Lower VSL

The performance or product 
measured almost meets the full 
intent of the requirement.   

Moderate VSL

High VSL

The performance or product 
The performance or product 
measured meets the majority of  measured does not meet the 
the intent of the requirement.    majority of the intent of the 
requirement, but does meet 
some of the intent. 

Severe VSL

The performance or product 
measured does not 
substantively meet the intent of 
the requirement.   

FERC Order of Violation Severity Levels

The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard 
meet the FERC Guidelines for assessing VSLs: 

Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance

Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than 
was required when levels of non‐compliance were used. 

Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties

A violation of a “binary” type requirement must be a “Severe” VSL. 
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance. 

Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

VSLs should not expand on what is required in the requirement. 

VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | OctoberJanuary 20192020 

4 

Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

Unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the 
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations. 

VRF Justification for TOP‐003‐4, Requirement R1 
The VRF did not change from the previously FERC approved TOP‐003‐3 Reliability Standard. 

VSL Justification for TOP‐003‐4, Requirement R1  
The VSL did not change from the previously FERC approved TOP‐003‐3 Reliability Standard. 

VRF Justification for TOP‐003‐4, Requirement R2  
The VRF did not change from the previously FERC approved TOP‐003‐3 Reliability Standard. 

VSL Justification for TOP‐003‐4, Requirement R2  
The VSL did not change from the previously FERC approved TOP‐003‐3 Reliability Standard. 

VRF Justification for TOP‐003‐4, Requirement R3 
The VRF did not change from the previously FERC approved TOP‐003‐3 Reliability Standard. 

VSL Justification for TOP‐003‐4, Requirement R3  
The VSL did not change from the previously FERC approved TOP‐003‐3 Reliability Standard. 

VRF Justification for TOP‐003‐4, Requirement R4  
The VRF did not change from the previously FERC approved TOP‐003‐3 Reliability Standard. 

VSL Justification for TOP‐003‐4, Requirement R4  
The VSL did not change from the previously FERC approved TOP‐003‐3 Reliability Standard. 

VRF Justification for TOP‐003‐4, Requirement R5 
The VRF did not change from the previously FERC approved TOP‐003‐3 Reliability Standard. 

VSL Justification for TOP‐003‐4, Requirement R5  
The VSL did not change from the previously FERC approved TOP‐003‐3 Reliability Standard.
VRF and VSL Justifications 
Project 2017‐07 Standards Alignment with Registration | OctoberJanuary 20192020 

5 

Standards Announcement

Project 2017-07 Standards Alignment with Registration
Final Ballots Open through January 23, 2020
Now Available
Final ballots for Project 2017-07 Standards Alignment with Registration are open through 8 p.m.
Eastern, Thursday, January 23, 2020 for the following Standards and Implementation Plan:
FAC-002-3 – Facility Interconnection Studies
IRO-010-3 – Reliability Coordinator Data Specification and Collection
MOD-031-3 – Demand and Energy Data
MOD-033-2 – Steady-State and Dynamic System Model Validation
NUC-001-4 – Nuclear Plant Interface Coordination
PRC-006-4 – Automatic Underfrequency Load Shedding
TOP-003-4 – Operational Reliability Data
Implementation Plan
Balloting

In the final ballot, votes are counted by exception. Votes from the previous ballot are automatically
carried over in the final ballot. Only members of the applicable ballot pools can cast a vote. Ballot pool
members who previously voted have the option to change their vote in the final ballot. Ballot pool
members who did not cast a vote during the previous ballot can vote in the final ballot.
Members of the ballot pool(s) associated with this project can log in and submit their votes by accessing
the Standards Balloting & Commenting System (SBS) here. If you experience issues navigating the SBS,
contact Linda Jenkins.
•

If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly
at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).

•

Passwords expire every 6 months and must be reset.

•

The SBS is not supported for use on mobile devices.

•

Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.

Next Steps

The voting results will be posted and announced after the ballots close. If approved, the standards will
be submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory
authorities.

RELIABILITY | RESILIENCE | SECURITY

Standards Development Process

For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Standards Developer, Laura Anderson (via email) or at (404)
446-9671.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2017-07 Standards Alignment with Registration
Final Ballot | January 2020

2

NERC Balloting Tool (/)

Dashboard (/)

Users

Ballots

Comment Forms

Login (/Users/Login) / Register (/Users/Register)

BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration FAC-002-3 FN 2 ST
Voting Start Date: 1/14/2020 9:03:32 AM
Voting End Date: 1/23/2020 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 231
Total Ballot Pool: 258
Quorum: 89.53
Quorum Established Date: 1/14/2020 9:18:38 AM
Weighted Segment Value: 99.69
Negative
Fraction
w/
Comment

Negative
Votes w/o
Comment

Abstain

No
Vote

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Segment:
1

66

1

60

1

0

0

0

3

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

54

1

49

1

0

0

0

1

4

Segment:
4

15

1

11

1

0

0

0

1

3

Segment:
5

62

1

49

0.98

1

0.02

0

2

10

Segment:
6

46

1

37

1

0

0

0

2

7

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.2

2

0.2

0

0

0

0

0

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
9
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

258

6.5

221

6.48

1

0.02

0

9

27

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Ben Engelby

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
1
Black Hills Corporation
Wes Wingen

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CenterPoint Energy
Houston Electric, LLC

Daniela Hammons

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy - Consumers
Energy Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

Douglas Webb

Stephanie Burns

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Los Angeles Department of
Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Angela Gaines

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Ginette Lacasse

Affirmative

N/A

Scott Miller

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Chris Hofmann

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Affirmative

N/A

1

Tennessee Valley Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Western Area Power
Administration

sean erickson

Affirmative

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

Bobbi Welch

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power Authority

David Rivera

Affirmative

N/A

Affirmative

N/A

3
NiSource - Northern
Dmitriy Bazylyuk
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Indiana Public Service Co.

Douglas Webb

Scott Miller

/

Segment

Organization

Voter

3

Ocala Utility Services

Neville Bowen

3

OGE Energy - Oklahoma
Gas and Electric Co.

3

Designated
Proxy
Brandon
McCormick

Ballot

NERC
Memo

None

N/A

Donald Hargrove

Affirmative

N/A

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley Authority

Ian Grant

Affirmative

N/A

Joe Tarantino

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City of Poplar Bluff

Neal Williams

None

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

Affirmative

N/A

5
AEP
Thomas Foltz
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Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Ameren - Ameren Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy - Consumers
Energy Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California Edison
Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
ExelonMachine Name: ERODVSBSWB01
Cynthia Lee
© 2020

Daniel Valle

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb Schrayshuen

Affirmative

N/A

5

Hydro-Qu?bec Production

Carl Pineault

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Ronald Bender

Affirmative

N/A

5

New York Power Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

N/A

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

Joe Tarantino

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

Affirmative

N/A

6

Great Plains Energy Jennifer
Kansas City Power and
Flandermeyer
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Light Co.

Douglas Webb

Douglas Webb

/

Segment

Organization

Voter

6

Great River Energy

Donna
Stephenson

6

Lincoln Electric System

6

Designated
Proxy
Michael
Brytowski

Ballot

NERC
Memo

Affirmative

N/A

Eric Ruskamp

Affirmative

N/A

Los Angeles Department of
Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

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/

Segment

Organization

Voter

6

Sacramento Municipal
Utility District

Jamie Cutlip

6

Salt River Project

6

Designated
Proxy

Affirmative

N/A

Bobby Olsen

Affirmative

N/A

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

David Reinecke

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Affirmative

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

Affirmative

N/A

10

Northeast Power
Guy V. Zito
Coordinating
Council
© 2020 - NERC Ver 4.3.0.0
Machine
Name: ERODVSBSWB01

Joe Tarantino

Ballot

NERC
Memo

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

NERC
Memo

Ballot

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Affirmative

N/A

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration IRO-010-3 FN 2 ST
Voting Start Date: 1/14/2020 9:03:48 AM
Voting End Date: 1/23/2020 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 229
Total Ballot Pool: 255
Quorum: 89.8
Quorum Established Date: 1/14/2020 9:18:44 AM
Weighted Segment Value: 99.69
Negative
Fraction
w/
Comment

Negative
Votes w/o
Comment

Abstain

No
Vote

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Segment:
1

66

1

60

1

0

0

0

3

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

53

1

48

1

0

0

0

1

4

Segment:
4

14

1

11

1

0

0

0

1

2

Segment:
5

61

1

48

0.98

1

0.02

0

2

10

Segment:
6

46

1

37

1

0

0

0

2

7

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.2

2

0.2

0

0

0

0

0

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
9
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/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

255

6.5

219

6.48

1

0.02

0

9

26

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Ben Engelby

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
1
Black Hills Corporation
Wes Wingen

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CenterPoint Energy
Houston Electric, LLC

Daniela Hammons

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy - Consumers
Energy Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

Douglas Webb

Stephanie Burns

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Los Angeles Department of
Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Angela Gaines

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Ginette Lacasse

Affirmative

N/A

Scott Miller

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Chris Hofmann

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Affirmative

N/A

1

Tennessee Valley Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Western Area Power
Administration

sean erickson

Affirmative

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

Bobbi Welch

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service Co.

Dmitriy Bazylyuk

Affirmative

N/A

None

N/A

3
Ocala Utility Services
Neville Bowen
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

Scott Miller

Brandon
McCormick

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3 - NERC Ver 4.3.0.0
WEC Energy
Group,
Thomas Breene
© 2020
Machine
Name:Inc.
ERODVSBSWB01

Affirmative

N/A

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5
Austin Energy
Lisa Martin
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Affirmative

N/A

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy - Consumers
Energy Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California Edison
Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

Daniel Valle

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/

Segment

Organization

Voter

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

5

Great River Energy

5

Designated
Proxy
Douglas Webb

Ballot

NERC
Memo

Affirmative

N/A

Preston Walsh

Affirmative

N/A

Herb Schrayshuen

Herb Schrayshuen

Affirmative

N/A

5

Hydro-Qu?bec Production

Carl Pineault

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Ronald Bender

Affirmative

N/A

5

New York Power Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

N/A

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
5
Xcel Energy, Inc.
Gerry Huitt

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Los Angeles Department of
Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

Abstain

N/A

6

Seminole Electric
David Reinecke
Cooperative,
Inc.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

NERC
Memo

Ballot

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Affirmative

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Affirmative

N/A

Douglas Webb

Previous

1

Next

Showing 1 to 255 of 255 entries
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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration MOD-031-3 FN 2 ST
Voting Start Date: 1/14/2020 9:04:08 AM
Voting End Date: 1/23/2020 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 229
Total Ballot Pool: 255
Quorum: 89.8
Quorum Established Date: 1/14/2020 9:19:31 AM
Weighted Segment Value: 99.69
Negative
Fraction
w/
Comment

Negative
Votes w/o
Comment

Abstain

No
Vote

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Segment:
1

66

1

60

1

0

0

0

3

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

53

1

48

1

0

0

0

1

4

Segment:
4

15

1

11

1

0

0

0

1

3

Segment:
5

60

1

49

0.98

1

0.02

0

1

9

Segment:
6

46

1

37

1

0

0

0

2

7

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.2

2

0.2

0

0

0

0

0

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
9
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

255

6.5

220

6.48

1

0.02

0

8

26

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Ben Engelby

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
1
Black Hills Corporation
Wes Wingen

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CenterPoint Energy
Houston Electric, LLC

Daniela Hammons

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy - Consumers
Energy Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

Douglas Webb

Stephanie Burns

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Los Angeles Department of
Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Angela Gaines

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Ginette Lacasse

Affirmative

N/A

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Chris Hofmann

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Affirmative

N/A

1

Tennessee Valley Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Western Area Power
Administration

sean erickson

Affirmative

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

Bobbi Welch

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service Co.

Dmitriy Bazylyuk

Affirmative

N/A

None

N/A

3
Ocala Utility Services
Neville Bowen
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

Scott Miller

Brandon
McCormick

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3 - NERC Ver 4.3.0.0
WEC Energy
Group,
Thomas Breene
© 2020
Machine
Name:Inc.
ERODVSBSWB01

Affirmative

N/A

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City of Poplar Bluff

Neal Williams

None

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren Missouri

Sam Dwyer

Affirmative

N/A

APS - Arizona Public
Kelsi Rigby
Service Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Affirmative

N/A

5

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy - Consumers
Energy Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California Edison
Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

Daniel Valle

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

5

Florida Municipal Power
Agency

Chris Gowder

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

5

Great River Energy

5

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Affirmative

N/A

Preston Walsh

Affirmative

N/A

Herb Schrayshuen

Herb Schrayshuen

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Ronald Bender

Affirmative

N/A

5

New York Power Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

N/A

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

Affirmative

N/A

5

Omaha Public Power
Mahmood Safi
DistrictMachine Name: ERODVSBSWB01
© 2020 - NERC Ver 4.3.0.0

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
WestarMachine
Energy Name: ERODVSBSWB01
Derek Brown
© 2020

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Los Angeles Department of
Water and Power

Anton Vu

None

N/A

Affirmative

N/A

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6
Manitoba Hydro
Blair Mukanik

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

Abstain

N/A

6

Seminole Electric
David Reinecke
Cooperative,
Inc.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

NERC
Memo

Ballot

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Affirmative

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Affirmative

N/A

Douglas Webb

Previous

1

Next

Showing 1 to 255 of 255 entries
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© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
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NERC Balloting Tool (/)

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration MOD-033-2 FN 2 ST
Voting Start Date: 1/14/2020 9:04:33 AM
Voting End Date: 1/23/2020 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 228
Total Ballot Pool: 254
Quorum: 89.76
Quorum Established Date: 1/14/2020 9:18:49 AM
Weighted Segment Value: 99.69
Negative
Fraction
w/
Comment

Negative
Votes w/o
Comment

Abstain

No
Vote

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Segment:
1

66

1

60

1

0

0

0

3

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

53

1

48

1

0

0

0

1

4

Segment:
4

15

1

11

1

0

0

0

1

3

Segment:
5

60

1

49

0.98

1

0.02

0

1

9

Segment:
6

45

1

36

1

0

0

0

2

7

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.2

2

0.2

0

0

0

0

0

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
9
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

254

6.5

219

6.48

1

0.02

0

8

26

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Ben Engelby

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
1
Black Hills Corporation
Wes Wingen

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CenterPoint Energy
Houston Electric, LLC

Daniela Hammons

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy - Consumers
Energy Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

Douglas Webb

Stephanie Burns

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Los Angeles Department of
Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Angela Gaines

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Ginette Lacasse

Affirmative

N/A

Scott Miller

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Chris Hofmann

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Affirmative

N/A

1

Tennessee Valley Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Western Area Power
Administration

sean erickson

Affirmative

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

Bobbi Welch

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service Co.

Dmitriy Bazylyuk

Affirmative

N/A

None

N/A

3
Ocala Utility Services
Neville Bowen
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

Scott Miller

Brandon
McCormick

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3 - NERC Ver 4.3.0.0
WEC Energy
Group,
Thomas Breene
© 2020
Machine
Name:Inc.
ERODVSBSWB01

Affirmative

N/A

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City of Poplar Bluff

Neal Williams

None

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

5

Ameren - Ameren Missouri

Sam Dwyer

Affirmative

N/A

APS - Arizona Public
Kelsi Rigby
Service Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Affirmative

N/A

5

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy - Consumers
Energy Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California Edison
Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

Daniel Valle

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

5

Florida Municipal Power
Agency

Chris Gowder

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

5

Great River Energy

5

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Affirmative

N/A

Preston Walsh

Affirmative

N/A

Herb Schrayshuen

Herb Schrayshuen

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Ronald Bender

Affirmative

N/A

5

New York Power Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

N/A

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

Affirmative

N/A

5

Omaha Public Power
Mahmood Safi
DistrictMachine Name: ERODVSBSWB01
© 2020 - NERC Ver 4.3.0.0

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
WestarMachine
Energy Name: ERODVSBSWB01
Derek Brown
© 2020

Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Los Angeles Department of
Water and Power

Anton Vu

None

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
6
Manitoba Hydro
Blair Mukanik

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

David Reinecke

Abstain

N/A

Affirmative

N/A

6

Snohomish County PUD
John Liang
No.
1
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

NERC
Memo

Ballot

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Affirmative

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Affirmative

N/A

Douglas Webb

Previous

1

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Showing 1 to 254 of 254 entries

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© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
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NERC Balloting Tool (/)

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Ballots

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration NUC-001-4 FN 2 ST
Voting Start Date: 1/14/2020 9:05:06 AM
Voting End Date: 1/23/2020 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 208
Total Ballot Pool: 229
Quorum: 90.83
Quorum Established Date: 1/14/2020 9:18:53 AM
Weighted Segment Value: 99.6
Negative
Fraction
w/
Comment

Negative
Votes w/o
Comment

Abstain

No
Vote

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Segment:
1

56

1

43

1

0

0

0

10

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

50

1

41

1

0

0

0

5

4

Segment:
4

12

0.9

9

0.9

0

0

0

2

1

Segment:
5

55

1

38

0.974

1

0.026

0

7

9

Segment:
6

41

1

30

1

0

0

0

7

4

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.2

2

0.2

0

0

0

0

0

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
9
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

229

6.4

176

6.374

1

0.026

0

31

21

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Ben Engelby

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

1

Black Hills Corporation

Wes Wingen

Affirmative

N/A

Affirmative

N/A

1
CenterPoint Energy
Daniela Hammons
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Houston Electric, LLC

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CMS Energy - Consumers
Energy Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Abstain

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

1

Los Angeles Department of
Water and Power

faranak sarbaz

None

N/A

1

Manitoba Hydro

Bruce Reimer

Abstain

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
1
National Grid USA
Michael Jones

Affirmative

N/A

Douglas Webb

Stephanie Burns

Scott Miller

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Steve Toosevich

Abstain

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Angela Gaines

Abstain

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Abstain

N/A

1

Public Utility District No. 1
of Chelan County

Ginette Lacasse

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Chris Hofmann

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Abstain

N/A

1

Tennessee Valley Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

1

Western Area Power
Administration

sean erickson

Abstain

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

Bobbi Welch

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista Corporation

Scott Kinney

Affirmative

N/A

Affirmative

N/A

3

Basin Electric Power
Jeremy Voll
Cooperative
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

BC Hydro and Power
Authority

Hootan Jarollahi

Abstain

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
3
MEAG Power
Roger Brand

Douglas Webb

Scott Miller

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service Co.

Dmitriy Bazylyuk

Abstain

N/A

3

Ocala Utility Services

Neville Bowen

None

N/A

3

OGE Energy - Oklahoma
Gas and Electric Co.

Donald Hargrove

Affirmative

N/A

3

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Abstain

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

Brandon
McCormick

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Abstain

N/A

3

Tennessee Valley Authority

Ian Grant

Affirmative

N/A

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Abstain

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
5
Ameren - Ameren Missouri
Sam Dwyer

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Abstain

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy - Consumers
Energy Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California Edison
Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

Daniel Valle

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

5

Florida Municipal Power
Agency

Chris Gowder

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

5

Great River Energy

5

Designated
Proxy

Ballot

NERC
Memo

Affirmative

N/A

Affirmative

N/A

Preston Walsh

Affirmative

N/A

Herb Schrayshuen

Herb Schrayshuen

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Abstain

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

5

Nebraska Public Power
District

Ronald Bender

Affirmative

N/A

5

New York Power Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Abstain

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

N/A

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

Douglas Webb

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

None

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Abstain

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Abstain

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren Services

Robert Quinlivan

Affirmative

N/A

Affirmative

N/A

6

APS - Arizona Public
Chinedu
Service Co.
Ochonogor
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Joe Tarantino

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

6

Lincoln Electric System

Eric Ruskamp

Affirmative

N/A

6

Manitoba Hydro

Blair Mukanik

Abstain

N/A

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service Co.

Joe O'Brien

Abstain

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Abstain

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Abstain

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

David Reinecke

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Abstain

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

Joe Tarantino

Douglas Webb

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/

Segment

Organization

Voter

Designated
Proxy

NERC
Memo

Ballot

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Affirmative

N/A

Previous

1

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Showing 1 to 229 of 229 entries

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NERC Balloting Tool (/)

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration PRC-006-4 FN 2 ST
Voting Start Date: 1/14/2020 9:04:50 AM
Voting End Date: 1/23/2020 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 230
Total Ballot Pool: 256
Quorum: 89.84
Quorum Established Date: 1/14/2020 9:19:38 AM
Weighted Segment Value: 99.38
Negative
Fraction
w/
Comment

Negative
Votes w/o
Comment

Abstain

No
Vote

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Segment:
1

66

1

59

1

0

0

0

4

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

54

1

49

1

0

0

0

1

4

Segment:
4

15

1

11

1

0

0

0

1

3

Segment:
5

60

1

48

0.96

2

0.04

0

1

9

Segment:
6

46

1

37

1

0

0

0

2

7

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.2

2

0.2

0

0

0

0

0

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
9
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Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

256

6.5

219

6.46

2

0.04

0

9

26

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Ben Engelby

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
1
Black Hills Corporation
Wes Wingen

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CenterPoint Energy
Houston Electric, LLC

Daniela Hammons

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy - Consumers
Energy Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

Douglas Webb

Stephanie Burns

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Los Angeles Department of
Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Angela Gaines

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Ginette Lacasse

Affirmative

N/A

Scott Miller

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Chris Hofmann

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

Joe Tarantino

Douglas Webb

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Western Area Power
Administration

sean erickson

Affirmative

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

Bobbi Welch

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power Authority

David Rivera

Affirmative

N/A

Affirmative

N/A

3
NiSource - Northern
Dmitriy Bazylyuk
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Indiana Public Service Co.

Douglas Webb

Scott Miller

/

Segment

Organization

Voter

3

Ocala Utility Services

Neville Bowen

3

OGE Energy - Oklahoma
Gas and Electric Co.

3

Designated
Proxy
Brandon
McCormick

Ballot

NERC
Memo

None

N/A

Donald Hargrove

Affirmative

N/A

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley Authority

Ian Grant

Affirmative

N/A

Joe Tarantino

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City of Poplar Bluff

Neal Williams

None

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

Affirmative

N/A

5
AEP
Thomas Foltz
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Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Ameren - Ameren Missouri

Sam Dwyer

Affirmative

N/A

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy - Consumers
Energy Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California Edison
Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

Affirmative

N/A

5 - NERC Ver 4.3.0.0
ExelonMachine Name: ERODVSBSWB01
Cynthia Lee
© 2020

Daniel Valle

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb Schrayshuen

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Ronald Bender

Affirmative

N/A

5

New York Power Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

N/A

Affirmative

N/A

5

OGE Energy - Oklahoma
Patrick Wells
Gas and
ElectricName:
Co. ERODVSBSWB01
© 2020 - NERC Ver 4.3.0.0
Machine

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Negative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

5

WEC Energy Group, Inc.

Janet OBrien

5

Westar Energy

Derek Brown

5

Xcel Energy, Inc.

6

Designated
Proxy

Ballot

NERC
Memo

None

N/A

Affirmative

N/A

Gerry Huitt

Affirmative

N/A

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Jennifer
Flandermeyer

Douglas Webb

Affirmative

N/A

6

Great River Energy

Donna
Stephenson

Michael
Brytowski

Affirmative

N/A

Affirmative

N/A

6
Lincoln Electric System
Eric Ruskamp
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Los Angeles Department of
Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

6

Salt River Project

Bobby Olsen

Affirmative

N/A

Affirmative

N/A

6 - NERC Ver 4.3.0.0
SanteeMachine
Cooper Name: ERODVSBSWB01
Michael Brown
© 2020

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

David Reinecke

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Affirmative

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10 - NERC Ver 4.3.0.0
Texas Machine
ReliabilityName:
Entity,ERODVSBSWB01
Inc.
Rachel Coyne
© 2020

Affirmative

N/A

Douglas Webb

/

Previous

1

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© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
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NERC Balloting Tool (/)

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration TOP-003-4 FN 2 ST
Voting Start Date: 1/14/2020 9:05:25 AM
Voting End Date: 1/23/2020 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 231
Total Ballot Pool: 257
Quorum: 89.88
Quorum Established Date: 1/14/2020 9:19:43 AM
Weighted Segment Value: 99.69
Negative
Fraction
w/
Comment

Negative
Votes w/o
Comment

Abstain

No
Vote

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Segment:
1

66

1

60

1

0

0

0

3

3

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

54

1

49

1

0

0

0

1

4

Segment:
4

14

1

11

1

0

0

0

1

2

Segment:
5

62

1

49

0.98

1

0.02

0

2

10

Segment:
6

46

1

37

1

0

0

0

2

7

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.2

2

0.2

0

0

0

0

0

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
9
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01

/

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

257

6.5

221

6.48

1

0.02

0

9

26

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Ben Engelby

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Affirmative

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
1
Black Hills Corporation
Wes Wingen

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CenterPoint Energy
Houston Electric, LLC

Daniela Hammons

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy - Consumers
Energy Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

Douglas Webb

Stephanie Burns

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Los Angeles Department of
Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Angela Gaines

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Ginette Lacasse

Affirmative

N/A

Scott Miller

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Chris Hofmann

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Affirmative

N/A

1

Tennessee Valley Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

Joe Tarantino

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Western Area Power
Administration

sean erickson

Affirmative

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

Bobbi Welch

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Affirmative

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power Authority

David Rivera

Affirmative

N/A

Affirmative

N/A

3
NiSource - Northern
Dmitriy Bazylyuk
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Indiana Public Service Co.

Douglas Webb

Scott Miller

/

Segment

Organization

Voter

3

Ocala Utility Services

Neville Bowen

3

OGE Energy - Oklahoma
Gas and Electric Co.

3

Designated
Proxy
Brandon
McCormick

Ballot

NERC
Memo

None

N/A

Donald Hargrove

Affirmative

N/A

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley Authority

Ian Grant

Affirmative

N/A

Joe Tarantino

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

Affirmative

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Modesto Irrigation District

Spencer Tacke

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

Affirmative

N/A

5
Ameren - Ameren Missouri
Sam Dwyer
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Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Affirmative

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy - Consumers
Energy Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Abstain

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California Edison
Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

Daniel Valle

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb Schrayshuen

Affirmative

N/A

5

Hydro-Qu?bec Production

Carl Pineault

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Affirmative

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Ronald Bender

Affirmative

N/A

5

New York Power Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

N/A

Douglas Webb

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

Joe Tarantino

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

Affirmative

N/A

6

Great Plains Energy Jennifer
Kansas City Power and
Flandermeyer
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Light Co.

Douglas Webb

Douglas Webb

/

Segment

Organization

Voter

6

Great River Energy

Donna
Stephenson

6

Lincoln Electric System

6

Designated
Proxy
Michael
Brytowski

Ballot

NERC
Memo

Affirmative

N/A

Eric Ruskamp

Affirmative

N/A

Los Angeles Department of
Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Missouri River Energy
Services

Gerald Tielke

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

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Segment

Organization

Voter

6

Sacramento Municipal
Utility District

Jamie Cutlip

6

Salt River Project

6

Designated
Proxy

Affirmative

N/A

Bobby Olsen

Affirmative

N/A

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

David Reinecke

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

Affirmative

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

Affirmative

N/A

10

Northeast Power
Guy V. Zito
Coordinating
Council
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Machine
Name: ERODVSBSWB01

Joe Tarantino

Ballot

NERC
Memo

Douglas Webb

/

Segment

Organization

Voter

Designated
Proxy

NERC
Memo

Ballot

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Dave Krueger

Affirmative

N/A

10

Texas Reliability Entity, Inc.

Rachel Coyne

Affirmative

N/A

Previous

1

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Showing 1 to 257 of 257 entries

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NERC Balloting Tool (/)

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BALLOT RESULTS
Ballot Name: 2017-07 Standards Alignment with Registration Implementation Plan FN 2 OT
Voting Start Date: 1/14/2020 9:05:46 AM
Voting End Date: 1/23/2020 8:00:00 PM
Ballot Type: OT
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 227
Total Ballot Pool: 256
Quorum: 88.67
Quorum Established Date: 1/14/2020 9:18:59 AM
Weighted Segment Value: 99.69
Negative
Fraction
w/
Comment

Negative
Votes w/o
Comment

Abstain

No
Vote

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Segment:
1

66

1

57

1

0

0

0

5

4

Segment:
2

6

0.6

6

0.6

0

0

0

0

0

Segment:
3

54

1

48

1

0

0

0

2

4

Segment:
4

14

1

10

1

0

0

0

1

3

Segment:
5

62

1

48

0.98

1

0.02

0

3

10

Segment:
6

45

1

35

1

0

0

0

2

8

Segment:
7

0

0

0

0

0

0

0

0

0

Segment:
8

2

0.2

2

0.2

0

0

0

0

0

0

0

0

0

0

Segment

Segment: 1
0.1
1
0.1
9
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Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
10

6

0.6

6

0.6

0

0

0

0

0

Totals:

256

6.5

213

6.48

1

0.02

0

13

29

Segment

Negative
Votes w/o
Comment

Abstain

No
Vote

BALLOT POOL MEMBERS
Show

All

Segment

Search: Search

entries

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

AEP - AEP Service
Corporation

Dennis Sauriol

Affirmative

N/A

1

Ameren - Ameren Services

Eric Scott

Affirmative

N/A

1

American Transmission
Company, LLC

LaTroy Brumfield

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle
Amarantos

Affirmative

N/A

1

Arizona Electric Power
Cooperative, Inc.

Ben Engelby

Affirmative

N/A

1

Austin Energy

Thomas Standifur

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Adrian Andreoiu

Abstain

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

None

N/A

None

N/A

© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
1
Black Hills Corporation
Wes Wingen

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

CenterPoint Energy
Houston Electric, LLC

Daniela Hammons

Affirmative

N/A

1

City Utilities of Springfield,
Missouri

Michael Buyce

Affirmative

N/A

1

CMS Energy - Consumers
Energy Company

Donald Lynd

Affirmative

N/A

1

Colorado Springs Utilities

Mike Braunstein

Affirmative

N/A

1

Con Ed - Consolidated
Edison Co. of New York

Dermot Smyth

Affirmative

N/A

1

Duke Energy

Laura Lee

Affirmative

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

Exelon

Daniel Gacek

Affirmative

N/A

1

FirstEnergy - FirstEnergy
Corporation

Julie Severino

None

N/A

1

Glencoe Light and Power
Commission

Terry Volkmann

Affirmative

N/A

1

Great Plains Energy Kansas City Power and
Light Co.

James McBee

Affirmative

N/A

1

Great River Energy

Gordon Pietsch

Affirmative

N/A

1

Hydro-Qu?bec
TransEnergie

Nicolas Turcotte

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Laura Nelson

Affirmative

N/A

1

International Transmission
Company Holdings
Corporation

Michael Moltane

Abstain

N/A

1

Lakeland Electric

Larry Watt

Affirmative

N/A

1

Lincoln Electric System

Danny Pudenz

Affirmative

N/A

1

Long Island Power
Authority

Robert Ganley

Affirmative

N/A

Douglas Webb

Stephanie Burns

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Los Angeles Department of
Water and Power

faranak sarbaz

Affirmative

N/A

1

Manitoba Hydro

Bruce Reimer

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

Affirmative

N/A

1

National Grid USA

Michael Jones

Affirmative

N/A

1

NB Power Corporation

Nurul Abser

Affirmative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Affirmative

N/A

1

New York Power Authority

Salvatore
Spagnolo

Affirmative

N/A

1

NextEra Energy - Florida
Power and Light Co.

Mike ONeil

Affirmative

N/A

1

NiSource - Northern
Indiana Public Service Co.

Steve Toosevich

Affirmative

N/A

1

OGE Energy - Oklahoma
Gas and Electric Co.

Terri Pyle

Affirmative

N/A

1

Omaha Public Power
District

Doug Peterchuck

Affirmative

N/A

1

OTP - Otter Tail Power
Company

Charles Wicklund

Affirmative

N/A

1

Platte River Power
Authority

Matt Thompson

Affirmative

N/A

1

PNM Resources - Public
Service Company of New
Mexico

Laurie Williams

Abstain

N/A

1

Portland General Electric
Co.

Angela Gaines

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Affirmative

N/A

1

Public Utility District No. 1
of Chelan County

Ginette Lacasse

Affirmative

N/A

Scott Miller

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Public Utility District No. 1
of Pend Oreille County

Kevin Conway

Affirmative

N/A

1

Public Utility District No. 1
of Snohomish County

Long Duong

Affirmative

N/A

1

Puget Sound Energy, Inc.

Theresa
Rakowsky

None

N/A

1

Sacramento Municipal
Utility District

Arthur Starkovich

Affirmative

N/A

1

Salt River Project

Chris Hofmann

Affirmative

N/A

1

Santee Cooper

Chris Wagner

Affirmative

N/A

1

SaskPower

Wayne
Guttormson

Affirmative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Bret Galbraith

Abstain

N/A

1

Sempra - San Diego Gas
and Electric

Mo Derbas

Affirmative

N/A

1

Southern Company Southern Company
Services, Inc.

Matt Carden

Affirmative

N/A

1

Sunflower Electric Power
Corporation

Paul Mehlhaff

Affirmative

N/A

1

Tacoma Public Utilities
(Tacoma, WA)

John Merrell

Affirmative

N/A

1

Tallahassee Electric (City
of Tallahassee, FL)

Scott Langston

Abstain

N/A

1

Tennessee Valley Authority

Gabe Kurtz

Affirmative

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

Affirmative

N/A

1

Unisource - Tucson
Electric Power Co.

John Tolo

Affirmative

N/A

1

Westar Energy

Allen Klassen

Affirmative

N/A

Joe Tarantino

Douglas Webb

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

1

Western Area Power
Administration

sean erickson

Affirmative

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

California ISO

Jamie Johnson

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Affirmative

N/A

2

Midcontinent ISO, Inc.

Bobbi Welch

Affirmative

N/A

2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Affirmative

N/A

3

AEP

Kent Feliks

Affirmative

N/A

3

Ameren - Ameren Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Vivian Moser

Affirmative

N/A

3

Austin Energy

W. Dwayne
Preston

Affirmative

N/A

3

Avista - Avista Corporation

Scott Kinney

Affirmative

N/A

3

Basin Electric Power
Cooperative

Jeremy Voll

Affirmative

N/A

3

BC Hydro and Power
Authority

Hootan Jarollahi

Abstain

N/A

3

Black Hills Corporation

Eric Egge

Affirmative

N/A

3

Bonneville Power
Administration

Ken Lanehome

Affirmative

N/A

3

City Utilities of Springfield,
Missouri

Scott Williams

Affirmative

N/A

3

CMS Energy - Consumers
Energy Company

Karl Blaszkowski

Affirmative

N/A

3

Colorado Springs Utilities

Hillary Dobson

Affirmative

N/A

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Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Karie Barczak

Affirmative

N/A

3

Duke Energy

Lee Schuster

Affirmative

N/A

3

Edison International Southern California Edison
Company

Romel Aquino

Affirmative

N/A

3

Exelon

Kinte Whitehead

Affirmative

N/A

3

FirstEnergy - FirstEnergy
Corporation

Aaron
Ghodooshim

None

N/A

3

Florida Municipal Power
Agency

Dale Ray

Affirmative

N/A

3

Georgia System
Operations Corporation

Scott McGough

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

John Carlson

Affirmative

N/A

3

Great River Energy

Brian Glover

Affirmative

N/A

3

Lakeland Electric

Patricia Boody

Affirmative

N/A

3

Lincoln Electric System

Jason Fortik

Affirmative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

None

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

3

Muscatine Power and
Water

Seth Shoemaker

Affirmative

N/A

3

National Grid USA

Brian Shanahan

Affirmative

N/A

3

Nebraska Public Power
District

Tony Eddleman

Affirmative

N/A

3

New York Power Authority

David Rivera

Affirmative

N/A

Affirmative

N/A

3
NiSource - Northern
Dmitriy Bazylyuk
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Indiana Public Service Co.

Douglas Webb

Scott Miller

/

Segment

Organization

Voter

3

Ocala Utility Services

Neville Bowen

3

OGE Energy - Oklahoma
Gas and Electric Co.

3

Designated
Proxy
Brandon
McCormick

Ballot

NERC
Memo

None

N/A

Donald Hargrove

Affirmative

N/A

Omaha Public Power
District

Aaron Smith

Affirmative

N/A

3

Owensboro Municipal
Utilities

Thomas Lyons

Affirmative

N/A

3

Platte River Power
Authority

Wade Kiess

Affirmative

N/A

3

PPL - Louisville Gas and
Electric Co.

James Frank

Affirmative

N/A

3

PSEG - Public Service
Electric and Gas Co.

James Meyer

None

N/A

3

Public Utility District No. 1
of Chelan County

Joyce Gundry

Affirmative

N/A

3

Puget Sound Energy, Inc.

Tim Womack

Affirmative

N/A

3

Sacramento Municipal
Utility District

Nicole Looney

Affirmative

N/A

3

Santee Cooper

James Poston

Affirmative

N/A

3

Seattle City Light

Laurie Hammack

Affirmative

N/A

3

Seminole Electric
Cooperative, Inc.

Michael Lee

Abstain

N/A

3

Sempra - San Diego Gas
and Electric

Bridget Silvia

Affirmative

N/A

3

Snohomish County PUD
No. 1

Holly Chaney

Affirmative

N/A

3

Southern Company Alabama Power Company

Joel Dembowski

Affirmative

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tennessee Valley Authority

Ian Grant

Affirmative

N/A

Joe Tarantino

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

3

Tri-State G and T
Association, Inc.

Janelle Marriott
Gill

Affirmative

N/A

3

WEC Energy Group, Inc.

Thomas Breene

Affirmative

N/A

3

Westar Energy

Bryan Taggart

Douglas Webb

Affirmative

N/A

3

Xcel Energy, Inc.

Joel Limoges

Amy Casuscelli

Affirmative

N/A

4

Alliant Energy Corporation
Services, Inc.

Larry Heckert

Affirmative

N/A

4

Austin Energy

Jun Hua

None

N/A

4

City Utilities of Springfield,
Missouri

John Allen

Affirmative

N/A

4

FirstEnergy - FirstEnergy
Corporation

Mark Garza

None

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Affirmative

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Affirmative

N/A

4

Municipal Energy Agency
of Nebraska

Brittany Millard

None

N/A

4

Public Utility District No. 1
of Snohomish County

John Martinsen

Affirmative

N/A

4

Public Utility District No. 2
of Grant County,
Washington

Karla Weaver

Affirmative

N/A

4

Sacramento Municipal
Utility District

Beth Tincher

Affirmative

N/A

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Jonathan Robbins

Abstain

N/A

4

Tacoma Public Utilities
(Tacoma, WA)

Hien Ho

Affirmative

N/A

4

WEC Energy Group, Inc.

Matthew Beilfuss

Affirmative

N/A

5

AEP

Thomas Foltz

Affirmative

N/A

Affirmative

N/A

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5
Ameren - Ameren Missouri
Sam Dwyer

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

APS - Arizona Public
Service Co.

Kelsi Rigby

Affirmative

N/A

5

Austin Energy

Lisa Martin

Affirmative

N/A

5

Avista - Avista Corporation

Glen Farmer

Affirmative

N/A

5

BC Hydro and Power
Authority

Helen Hamilton
Harding

Abstain

N/A

5

Black Hills Corporation

George Tatar

Affirmative

N/A

5

Boise-Kuna Irrigation
District - Lucky Peak
Power Plant Project

Mike Kukla

Affirmative

N/A

5

Bonneville Power
Administration

Scott Winner

Affirmative

N/A

5

Brazos Electric Power
Cooperative, Inc.

Shari Heino

None

N/A

5

Choctaw Generation
Limited Partnership, LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

CMS Energy - Consumers
Energy Company

David Greyerbiehl

Affirmative

N/A

5

Con Ed - Consolidated
Edison Co. of New York

William Winters

Affirmative

N/A

5

Cowlitz County PUD

Deanna Carlson

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Adrian Raducea

None

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Edison International Southern California Edison
Company

Neil Shockey

Affirmative

N/A

5

Entergy

Jamie Prater

Affirmative

N/A

5

Exelon

Cynthia Lee

Affirmative

N/A

Daniel Valle

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

FirstEnergy - FirstEnergy
Solutions

Robert Loy

None

N/A

5

Florida Municipal Power
Agency

Chris Gowder

Affirmative

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Marcus Moor

Affirmative

N/A

5

Great River Energy

Preston Walsh

Affirmative

N/A

5

Herb Schrayshuen

Herb Schrayshuen

Affirmative

N/A

5

Hydro-Qu?bec Production

Carl Pineault

Affirmative

N/A

5

Lakeland Electric

Jim Howard

None

N/A

5

Lincoln Electric System

Kayleigh
Wilkerson

Affirmative

N/A

5

Los Angeles Department of
Water and Power

Glenn Barry

None

N/A

5

Lower Colorado River
Authority

Teresa Cantwell

Affirmative

N/A

5

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts Municipal
Wholesale Electric
Company

Anthony Stevens

Abstain

N/A

5

Muscatine Power and
Water

Neal Nelson

Affirmative

N/A

5

National Grid USA

Elizabeth Spivak

Affirmative

N/A

5

NaturEner USA, LLC

Eric Smith

None

N/A

5

Nebraska Public Power
District

Ronald Bender

Affirmative

N/A

5

New York Power Authority

Shivaz Chopra

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service Co.

Kathryn Tackett

Affirmative

N/A

5

Northern California Power
Agency

Marty Hostler

Negative

N/A

Douglas Webb

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

OGE Energy - Oklahoma
Gas and Electric Co.

Patrick Wells

Affirmative

N/A

5

Omaha Public Power
District

Mahmood Safi

Affirmative

N/A

5

Ontario Power Generation
Inc.

Constantin
Chitescu

Affirmative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

PPL - Louisville Gas and
Electric Co.

JULIE
HOSTRANDER

Affirmative

N/A

5

PSEG - PSEG Fossil LLC

Tim Kucey

Affirmative

N/A

5

Public Utility District No. 1
of Chelan County

Meaghan Connell

Affirmative

N/A

5

Public Utility District No. 1
of Snohomish County

Sam Nietfeld

Affirmative

N/A

5

Public Utility District No. 2
of Grant County,
Washington

Alex Ybarra

Affirmative

N/A

5

Puget Sound Energy, Inc.

Lynn Murphy

None

N/A

5

Sacramento Municipal
Utility District

Nicole Goi

Affirmative

N/A

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Tommy Curtis

Affirmative

N/A

5

Seattle City Light

Faz Kasraie

Affirmative

N/A

5

Seminole Electric
Cooperative, Inc.

David Weber

Abstain

N/A

5

Sempra - San Diego Gas
and Electric

Jennifer Wright

Affirmative

N/A

5

Southern Company Southern Company
Generation

William D. Shultz

Affirmative

N/A

5

SunPower

Bradley Collard

None

N/A

Joe Tarantino

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/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

5

Tacoma Public Utilities
(Tacoma, WA)

Ozan Ferrin

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Wendy Center

Affirmative

N/A

5

WEC Energy Group, Inc.

Janet OBrien

None

N/A

5

Westar Energy

Derek Brown

Affirmative

N/A

5

Xcel Energy, Inc.

Gerry Huitt

Affirmative

N/A

6

AEP - AEP Marketing

Yee Chou

Affirmative

N/A

6

Ameren - Ameren Services

Robert Quinlivan

Affirmative

N/A

6

APS - Arizona Public
Service Co.

Chinedu
Ochonogor

Affirmative

N/A

6

Basin Electric Power
Cooperative

Jerry Horner

None

N/A

6

Berkshire Hathaway PacifiCorp

Sandra Shaffer

Affirmative

N/A

6

Black Hills Corporation

Eric Scherr

Affirmative

N/A

6

Bonneville Power
Administration

Andrew Meyers

Affirmative

N/A

6

Cleco Corporation

Robert Hirchak

Affirmative

N/A

6

Colorado Springs Utilities

Melissa Brown

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Christopher
Overberg

Affirmative

N/A

6

Duke Energy

Greg Cecil

Affirmative

N/A

6

Entergy

Julie Hall

None

N/A

6

Exelon

Becky Webb

Affirmative

N/A

6

FirstEnergy - FirstEnergy
Solutions

Ann Carey

None

N/A

6

Florida Municipal Power
Agency

Richard
Montgomery

Affirmative

N/A

Affirmative

N/A

6

Great Plains Energy Jennifer
Kansas City Power and
Flandermeyer
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Light Co.

Douglas Webb

Douglas Webb

/

Segment

Organization

Voter

6

Great River Energy

Donna
Stephenson

6

Lincoln Electric System

6

Designated
Proxy

Affirmative

N/A

Eric Ruskamp

Affirmative

N/A

Los Angeles Department of
Water and Power

Anton Vu

None

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

6

Muscatine Power and
Water

Nick Burns

Affirmative

N/A

6

NextEra Energy - Florida
Power and Light Co.

Justin Welty

None

N/A

6

NiSource - Northern
Indiana Public Service Co.

Joe O'Brien

Affirmative

N/A

6

Northern California Power
Agency

Dennis Sismaet

Abstain

N/A

6

OGE Energy - Oklahoma
Gas and Electric Co.

Sing Tay

Affirmative

N/A

6

Omaha Public Power
District

Joel Robles

Affirmative

N/A

6

Platte River Power
Authority

Sabrina Martz

Affirmative

N/A

6

Portland General Electric
Co.

Daniel Mason

Affirmative

N/A

6

PPL - Louisville Gas and
Electric Co.

Linn Oelker

Affirmative

N/A

6

PSEG - PSEG Energy
Resources and Trade LLC

Luiggi Beretta

Affirmative

N/A

6

Public Utility District No. 1
of Chelan County

Davis Jelusich

Affirmative

N/A

6

Public Utility District No. 2
of Grant County,
Washington

LeRoy Patterson

Affirmative

N/A

6

Sacramento Municipal
Utility District

Jamie Cutlip

Affirmative

N/A

Affirmative

N/A

6 - NERC Ver 4.3.0.0
Salt River
Project
Bobby Olsen
© 2020
Machine
Name: ERODVSBSWB01

Michael
Brytowski

Ballot

NERC
Memo

Joe Tarantino

/

Segment

Organization

Voter

Designated
Proxy

Ballot

NERC
Memo

6

Santee Cooper

Michael Brown

Affirmative

N/A

6

Seattle City Light

Charles Freeman

Affirmative

N/A

6

Seminole Electric
Cooperative, Inc.

David Reinecke

Abstain

N/A

6

Snohomish County PUD
No. 1

John Liang

Affirmative

N/A

6

Southern Company Southern Company
Generation

Ron Carlsen

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Terry Gifford

None

N/A

6

Tennessee Valley Authority

Marjorie Parsons

Affirmative

N/A

6

WEC Energy Group, Inc.

David Hathaway

None

N/A

6

Westar Energy

Grant Wilkerson

Affirmative

N/A

6

Western Area Power
Administration

Rosemary Jones

Affirmative

N/A

6

Xcel Energy, Inc.

Carrie Dixon

Affirmative

N/A

8

David Kiguel

David Kiguel

Affirmative

N/A

8

Roger Zaklukiewicz

Roger
Zaklukiewicz

Affirmative

N/A

9

Commonwealth of
Massachusetts
Department of Public
Utilities

Donald Nelson

Affirmative

N/A

10

Midwest Reliability
Organization

Russel Mountjoy

Affirmative

N/A

10

New York State Reliability
Council

ALAN ADAMSON

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

Affirmative

N/A

10

SERC Reliability
Dave Krueger
Corporation
© 2020 - NERC Ver 4.3.0.0
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Douglas Webb

/

Segment
10

Organization
Texas Reliability Entity, Inc.

Voter
Rachel Coyne

Designated
Proxy

NERC
Memo

Ballot
Affirmative
Previous

N/A
1

Next

Showing 1 to 256 of 256 entries

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Exhibit F
Standard Drafting Team Roster
Project 2017-07 Standards Alignment with Registration

RELIABILITY | RESILIENCE | SECURITY

Project 2017-07 Standards Alignment with
Registration Drafting Team Roster
Name

Entity

Chair

Mark Atkins

AESI, Inc.

Vice Chair

Robert Staton

Xcel Energy

Members

Stephen Wendling

American Transmission Company

Shannon Mickens

Southwest Power Pool

Leslie Williams

ERCOT

LaTroy Brumfield

American Transmission Company

Matthew Harward

Southwest Power Pool

PMOS Liaison

Michael Brytowski

Great River Energy

NERC Staff

Laura Anderson – Standards
Developer

North American Electric Reliability
Corporation

Lauren Perotti – Senior Counsel

North American Electric Reliability
Corporation

RELIABILITY | RESILIENCE | SECURITY